EXHIBIT 13.01
southwest gas 2003 annual report
PAGE 21
consolidated selected financial statistics
(thousands of dollars, except per share amounts) | ||||||||||||||||||||
YEAR ENDED DECEMBER 31, | 2003 | 2002 | 2001 | 2000 | 1999 | |||||||||||||||
Operating revenues | $ | 1,231,004 | $ | 1,320,909 | $ | 1,396,688 | $ | 1,034,087 | $ | 936,866 | ||||||||||
Operating expenses | 1,095,899 | 1,174,410 | 1,262,705 | 905,457 | 805,654 | |||||||||||||||
Operating income | $ | 135,105 | $ | 146,499 | $ | 133,983 | $ | 128,630 | $ | 131,212 | ||||||||||
Net income | $ | 38,502 | $ | 43,965 | $ | 37,156 | $ | 38,311 | $ | 39,310 | ||||||||||
Total assets at year end | $ | 2,608,106 | $ | 2,432,928 | $ | 2,369,612 | $ | 2,232,337 | $ | 1,923,442 | ||||||||||
CAPITALIZATION AT YEAR END | ||||||||||||||||||||
Common equity | $ | 630,467 | $ | 596,167 | $ | 561,200 | $ | 533,467 | $ | 505,425 | ||||||||||
Mandatorily redeemable preferred | — | 60,000 | 60,000 | 60,000 | 60,000 | |||||||||||||||
Subordinated debentures | 100,000 | — | — | — | — | |||||||||||||||
Long-term debt | 1,121,164 | 1,092,148 | 796,351 | 896,417 | 859,291 | |||||||||||||||
$ | 1,851,631 | $ | 1,748,315 | $ | 1,417,551 | $ | 1,489,884 | $ | 1,424,716 | |||||||||||
COMMON STOCK DATA | ||||||||||||||||||||
Return on average common equity | 6.3 | % | 7.5 | % | 6.8 | % | 7.4 | % | 8.0 | % | ||||||||||
Earnings per share | $ | 1.14 | $ | 1.33 | $ | 1.16 | $ | 1.22 | $ | 1.28 | ||||||||||
Diluted earnings per share | $ | 1.13 | $ | 1.32 | $ | 1.15 | $ | 1.21 | $ | 1.27 | ||||||||||
Dividends paid per share | $ | 0.82 | $ | 0.82 | $ | 0.82 | $ | 0.82 | $ | 0.82 | ||||||||||
Payout ratio | 72 | % | 62 | % | 71 | % | 67 | % | 64 | % | ||||||||||
Book value per share at year end | $ | 18.42 | $ | 17.91 | $ | 17.27 | $ | 16.82 | $ | 16.31 | ||||||||||
Market value per share at year end | $ | 22.45 | $ | 23.45 | $ | 22.35 | $ | 21.88 | $ | 23.00 | ||||||||||
Market value per share to book | 122 | % | 131 | % | 129 | % | 130 | % | 141 | % | ||||||||||
Common shares outstanding | 34,232 | 33,289 | 32,493 | 31,710 | 30,985 | |||||||||||||||
Number of common shareholders | 22,616 | 22,119 | 23,243 | 24,092 | 22,989 | |||||||||||||||
Ratio of earnings to fixed charges | 1.60 | 1.68 | 1.59 | 1.60 | 1.78 |
southwest gas 2003 annual report
PAGE 22
natural gas operations
(thousands of dollars) | ||||||||||||||||||||
YEAR ENDED DECEMBER 31, | 2003 | 2002 | 2001 | 2000 | 1999 | |||||||||||||||
Sales | $ | 984,966 | $ | 1,069,917 | $ | 1,149,918 | $ | 816,358 | $ | 740,900 | ||||||||||
Transportation | 49,387 | 45,983 | 43,184 | 54,353 | 50,255 | |||||||||||||||
Operating revenue | 1,034,353 | 1,115,900 | 1,193,102 | 870,711 | 791,155 | |||||||||||||||
Net cost of gas sold | 482,503 | 563,379 | 677,547 | 394,711 | 330,031 | |||||||||||||||
Operating margin | 551,850 | 552,521 | 515,555 | 476,000 | 461,124 | |||||||||||||||
EXPENSES | ||||||||||||||||||||
Operations and maintenance | 266,862 | 264,188 | 253,026 | 231,175 | 221,258 | |||||||||||||||
Depreciation and amortization | 120,791 | 115,175 | 104,498 | 94,689 | 88,254 | |||||||||||||||
Taxes other than income taxes | 35,910 | 34,565 | 32,780 | 29,819 | 27,610 | |||||||||||||||
Operating income | $ | 128,287 | $ | 138,593 | $ | 125,251 | $ | 120,317 | $ | 124,002 | ||||||||||
Contribution to consolidated net | $ | 34,211 | $ | 39,228 | $ | 32,626 | $ | 33,908 | $ | 35,473 | ||||||||||
Total assets at year end | $ | 2,528,332 | $ | 2,345,407 | $ | 2,289,111 | $ | 2,154,641 | $ | 1,855,114 | ||||||||||
Net gas plant at year end | $ | 2,175,736 | $ | 2,034,459 | $ | 1,825,571 | $ | 1,686,082 | $ | 1,581,102 | ||||||||||
Construction expenditures and | $ | 228,288 | $ | 263,576 | $ | 248,352 | $ | 205,161 | $ | 207,773 | ||||||||||
CASH FLOW, NET | ||||||||||||||||||||
From operating activities | $ | 187,122 | $ | 281,329 | $ | 103,848 | $ | 109,872 | $ | 165,220 | ||||||||||
From investing activities | (249,300 | ) | (243,373 | ) | (246,462 | ) | (203,325 | ) | (207,024 | ) | ||||||||||
From financing activities | 60,815 | (49,187 | ) | 154,727 | 95,481 | 40,674 | ||||||||||||||
Net change in cash | $ | (1,363 | ) | $ | (11,231 | ) | $ | 12,113 | $ | 2,028 | $ | (1,130 | ) | |||||||
(thousands of therms) | ||||||||||||||||||||
TOTAL THROUGHPUT | ||||||||||||||||||||
Residential | 593,048 | 588,215 | 589,943 | 571,378 | 554,507 | |||||||||||||||
Small commercial | 279,154 | 280,271 | 279,965 | 272,673 | 266,030 | |||||||||||||||
Large commercial | 100,422 | 121,500 | 107,583 | 63,908 | 62,566 | |||||||||||||||
Industrial/Other | 157,305 | 224,055 | 283,772 | 199,715 | 154,306 | |||||||||||||||
Transportation | 1,336,901 | 1,325,149 | 1,268,203 | 1,482,700 | 1,186,859 | |||||||||||||||
Total throughput | 2,466,830 | 2,539,190 | 2,529,466 | 2,590,374 | 2,224,268 | |||||||||||||||
Weighted average cost of gas | $ | 0.46 | $ | 0.38 | $ | 0.55 | $ | 0.42 | $ | 0.28 | ||||||||||
Customers at year end | 1,531,000 | 1,455,000 | 1,397,000 | 1,337,000 | 1,274,000 | |||||||||||||||
Employees at year end | 2,550 | 2,546 | 2,507 | 2,491 | 2,482 | |||||||||||||||
Degree days – actual | 1,772 | 1,912 | 1,963 | 1,938 | 1,928 | |||||||||||||||
Degree days – ten-year average | 1,931 | 1,963 | 1,970 | 1,991 | 2,031 |
southwest gas 2003 annual report
PAGE 23
management’s discussion and analysis of
financial condition and results of operations
EXECUTIVE SUMMARY
The following discussion of Southwest Gas Corporation and subsidiaries (the “Company”) includes information related to regulated natural gas transmission and distribution activities and non-regulated activities.
The Company is comprised of two business segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest is engaged in the business of purchasing, transporting, and distributing natural gas in portions of Arizona, Nevada, and California. Southwest is the largest distributor in Arizona, selling and transporting natural gas in most of central and southern Arizona, including the Phoenix and Tucson metropolitan areas. Southwest is also the largest distributor and transporter of natural gas in Nevada, serving the Las Vegas metropolitan area and northern Nevada. In addition, Southwest distributes and transports natural gas in portions of California, including the Lake Tahoe area and the high desert and mountain areas in San Bernardino County.
Northern Pipeline Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.
consolidated results of operations
(thousands of dollars, except per share amounts) | |||||||||
YEAR ENDED DECEMBER 31, | 2003 | 2002 | 2001 | ||||||
CONTRIBUTION TO NET INCOME | |||||||||
Natural gas operations | $ | 34,211 | $ | 39,228 | $ | 32,626 | |||
Construction services | 4,291 | 4,737 | 4,530 | ||||||
Net income | $ | 38,502 | $ | 43,965 | $ | 37,156 | |||
EARNINGS PER SHARE | |||||||||
Natural gas operations | $ | 1.01 | $ | 1.19 | $ | 1.02 | |||
Construction services | 0.13 | 0.14 | 0.14 | ||||||
Consolidated | $ | 1.14 | $ | 1.33 | $ | 1.16 | |||
See separate discussions at Results of Natural Gas Operations and Results of Construction Services. Average shares outstanding increased by 807,000 between 2003 and 2002, and 831,000 between 2002 and 2001, primarily resulting from continuing issuances under the Dividend Reinvestment and Stock Purchase Plan (“DRSPP”).
As reflected in the table above, the natural gas operations segment accounted for an average of 89 percent of consolidated net income over the past three years. As such, management’s main focus is on that segment.
Southwest’s operating revenues are recognized from the distribution and transportation of natural gas (and related services) billed to customers. An estimate of the amount of natural gas distributed, but not yet billed, to residential and commercial customers from the latest meter reading date to the end of the reporting period is also recognized in revenues.
Margin is the measure of utility revenues less the net cost of gas sold. Management uses margin as a main benchmark in comparing operating results from period to period. The three principal factors affecting utility margin are general rate relief, weather, and customer growth.
southwest gas 2003 annual report
PAGE 24
management’s discussion and analysis of
financial condition and results of operations
Rates charged to customers vary according to customer class and rate jurisdiction and are set by the individual state and federal regulatory commissions that govern Southwest’s service territories. Southwest makes periodic filings for rate adjustments as the costs of providing service (including the cost of natural gas purchased) change and as additional investments in new or replacement pipeline and related facilities are made. (See the section on Rates and Regulatory Proceedings for additional information). Rates are intended to provide for recovery of all prudently incurred costs and provide a reasonable return on investment. The mix of fixed and variable components in rates assigned to various customer classes (rate design) can significantly impact the operating margin actually realized by Southwest.
Weather is a significant driver of natural gas volumes used by residential and small commercial customers and is the main reason for volatility in margin. Space heating-related volumes are the primary component of billings for these customer classes and are concentrated in the months of November to April for the majority of the Company’s customers. Variances in temperatures from normal levels, especially during these months, have a significant impact on the margin and associated net income of the Company.
Customer growth, excluding acquisitions, has averaged five percent annually over the past 10 years and over four percent annually during the past three years. Incremental margin has accompanied this customer growth, but the costs associated with creating and maintaining the infrastructure needed to accommodate these customers also have been significant. The timing of including these costs in rates is often delayed (regulatory lag) and results in a reduction of current-period earnings.
Management has attempted to mitigate the regulatory lag by being judicious in its staffing levels through the effective use of technology. During the past decade while adding nearly 600,000 customers, Southwest only increased staffing levels by 232. During this same period, Southwest’s customer to employee ratio has climbed from 402/1 to 600/1, one of the best in the industry. It has accomplished this without sacrificing service quality. Examples of technological improvements over the last few years include electronic order routing, an electronic mapping system and, most recently, a work management system.
The results of the natural gas operations segment and the overall results of the Company are heavily dependent upon the three components noted previously (general rate relief, weather, and customer growth). Significant changes in these components (primarily weather) have contributed to somewhat volatile earnings. Management continues to work with its regulatory commissions in designing rate structures that provide affordable and reliable service to its customers while mitigating the volatility in prices to customers and stabilizing returns to investors.
As of December 31, 2003, Southwest had 1,531,000 residential, commercial, industrial, and other natural gas customers, of which 851,000 customers were located in Arizona, 542,000 in Nevada, and 138,000 in California. Residential and commercial customers represented over 99 percent of the total customer base. During 2003, Southwest added 67,000 customers (excluding 9,000 associated with the acquisition of Black Mountain Gas Company (“BMG”) in October 2003), a five percent increase, of which 30,000 customers were added in Arizona, 31,000 in Nevada, and 6,000 in California. These additions are largely attributed to population growth in the service areas. Based on current commitments from builders, customer growth is expected to be between four and five percent in 2004. During 2003, 56 percent of operating margin was earned in Arizona, 36 percent in Nevada, and 8 percent in California. During this same period, Southwest earned 84 percent of operating margin from residential and small commercial customers, 6 percent from other sales customers, and 10 percent from transportation customers. These patterns are expected to continue.
southwest gas 2003 annual report
PAGE 25
management’s discussion and analysis of
financial condition and results of operations
RESULTS OF NATURAL GAS OPERATIONS
(thousands of dollars) | |||||||||
YEAR ENDED DECEMBER 31, | 2003 | 2002 | 2001 | ||||||
Gas operating revenues | $ | 1,034,353 | $ | 1,115,900 | $ | 1,193,102 | |||
Net cost of gas sold | 482,503 | 563,379 | 677,547 | ||||||
Operating margin | 551,850 | 552,521 | 515,555 | ||||||
Operations and maintenance expense | 266,862 | 264,188 | 253,026 | ||||||
Depreciation and amortization | 120,791 | 115,175 | 104,498 | ||||||
Taxes other than income taxes | 35,910 | 34,565 | 32,780 | ||||||
Operating income | 128,287 | 138,593 | 125,251 | ||||||
Other income (expense) | 2,955 | 3,108 | 7,694 | ||||||
Net interest deductions | 76,251 | 78,505 | 78,746 | ||||||
Net interest deductions on subordinated debentures | 2,680 | — | — | ||||||
Preferred securities distributions | 4,180 | 5,475 | 5,475 | ||||||
Income before income taxes | 48,131 | 57,721 | 48,724 | ||||||
Income tax expense | 13,920 | 18,493 | 16,098 | ||||||
Contribution to consolidated net income | $ | 34,211 | $ | 39,228 | $ | 32,626 | |||
2003 vs. 2002
Contribution from natural gas operations declined $5 million in 2003 compared to 2002. The decrease was principally the result of lower operating margin and increased operating expenses, partially offset by decreased financing costs.
Operating margin decreased $671,000 in 2003 as compared to 2002. Approximately 67,000 customers were added during the last 12 months, a growth rate of five percent. Another 9,000 customers were added in October 2003 with the acquisition of Black Mountain Gas Company. New customers contributed $16 million in incremental margin. Differences in heating demand caused by weather variations between years resulted in a $13 million margin decrease as warmer-than-normal temperatures were experienced during both years. During 2003, operating margin was negatively impacted $32 million by the weather, while in 2002 the negative impact was $19 million. Conservation, energy efficiency and other factors accounted for the remainder of the decline.
Operations and maintenance expense increased $2.7 million, or one percent, compared to 2002. The impacts of general cost increases and costs associated with the continued expansion and upgrading of the gas system to accommodate customer growth were offset by cost-curbing management initiatives begun in the fourth quarter of 2002. Going forward, operations and maintenance expenses overall are expected to trend upward corresponding to the customer growth rate and inflation. The costs of additional regulation, social programs, medical costs and pensions are some of the primary factors responsible for this trend.
Depreciation expense and general taxes increased $7 million, or five percent, as a result of construction activities. Average gas plant in service increased $231 million, or nine percent, as compared to 2002. The increase reflects ongoing capital expenditures for the upgrade of existing operating facilities and the expansion of the system to accommodate continued customer growth.
southwest gas 2003 annual report
PAGE 26
management’s discussion and analysis of
financial condition and results of operations
Other income (expense) decreased $153,000 between years. The prior year included income of $2.2 million related to several non-recurring items. Interest income (primarily on purchased gas adjustment (“PGA”) balances) declined $1.6 million between years. Improvements in returns on long-term investments substantially offset the negative factors.
Net financing costs declined $869,000 between years primarily due to lower interest rates on variable-rate debt and interest savings generated from the refinancing of industrial development revenue bonds and preferred securities instruments in 2003. Interest costs are expected to trend upward in 2004 as the Company finances the infrastructure associated with customer growth.
During 2003, Southwest recognized $2 million of income tax benefits associated with plant-related items. In 2002, Southwest recognized $2.7 million of income tax benefits associated with state taxes, plant, and non-plant related items.
2002 vs. 2001
The gas segment contribution to consolidated net income for 2002 increased $6.6 million from 2001. Growth in operating margin was partially offset by higher operating costs and a decline in other income (expense).
Operating margin increased $37 million, or seven percent, in 2002 as compared to 2001. The increase was a result of rate relief and customer growth, partially offset by the impacts of warm weather between periods. General rate relief granted during the fourth quarter of 2001, in both Arizona and Nevada, increased operating margin by $33 million. Southwest added 58,000 customers during 2002, an increase of four percent. New customers contributed $20 million in incremental margin. Differences in heating demand caused by weather variations between periods and conservation resulted in a $16 million margin decrease. Warmer-than-normal temperatures were experienced during the second and fourth quarters of 2002, whereas during 2001, temperatures were relatively normal.
Operations and maintenance expense increased $11.2 million, or four percent, reflecting general increases in labor and maintenance costs, and incremental costs associated with servicing additional customers. Uncollectible expenses in 2002 were slightly below the amounts recorded in 2001 as natural gas prices declined, lowering average customer bills.
Depreciation expense and general taxes increased $12.5 million, or nine percent, as a result of construction activities. Average gas plant in service increased $207 million, or eight percent, compared to the prior year. This was attributed to the continued expansion and upgrading of the gas system to accommodate customer growth.
Other income (expense) declined $4.6 million between years principally because of a $5 million decrease in interest income earned on the balance of deferred purchased gas costs. Significant components of the 2002 balance included: an $8.9 million gain on the sale of undeveloped property, $4 million of net merger-related litigation costs, and $2.7 million of charges associated with the settlement of a regulatory issue in California.
Net interest deductions declined $241,000 between years. Strong cash flows during the first half of 2002, from the recovery of previously deferred purchased gas costs and general rate relief, mitigated the amount of incremental borrowings needed to finance construction expenditures. Declining interest rates on variable-rate debt instruments were also a contributing favorable factor.
During 2002, Southwest recognized $2.7 million of income tax benefits associated with state taxes, plant, and non-plant related items. In 2001, the resolution of state income tax issues resulted in a $2.5 million income tax benefit.
southwest gas 2003 annual report
PAGE 27
management’s discussion and analysis of
financial condition and results of operations
RATES AND REGULATORY PROCEEDINGS
Arizona General Rate Case. In May 2000, Southwest last filed a general rate application with the Arizona Corporation Commission (“ACC”) for its Arizona rate jurisdiction. The ACC authorized a general rate increase of $21.6 million effective November 2001. Management has not determined the timing of filing its next general rate case in Arizona.
Nevada General Rate Cases. In March 2004, Southwest filed general rate applications with the Public Utilities Commission of Nevada (“PUCN”), which included annual increases of $8.6 million for northern Nevada and $18.9 million in southern Nevada. A PUCN decision is expected in the third quarter of 2004.
In July 2001, Southwest filed general rate applications with the PUCN for its southern Nevada and northern Nevada rate jurisdictions. The PUCN authorized general rate increases of $13.5 million in southern Nevada and $5.9 million in northern Nevada effective December 2001.
California General Rate Cases. In February 2002, Southwest filed general rate applications with the California Public Utilities Commission (“CPUC”) for its northern and southern California jurisdictions. The applications sought annual increases over a five-year rate case cycle with a cumulative total of $6.3 million in northern California and $17.2 million in southern California. The last general rate increases received in California were January 1998 in northern California and January 1995 in southern California.
In July 2002, the Office of Ratepayer Advocates (“ORA”) filed testimony in the rate case recommending significant reductions to the rate increases sought by Southwest. The ORA concurred with the majority of the Southwest rate design proposals including a margin tracking mechanism to mitigate weather-related and other usage variations. At the hearing that was held in August 2002, Southwest modified its proposal from a five-year to a three-year rate case cycle and accordingly reduced its cumulative request to $4.8 million in northern California and $10.7 million in southern California. For 2003, the amounts requested were $2.6 million in northern California and $5.7 million in southern California. The final general rate case decision, originally anticipated to have an effective date of January 2003, was delayed due to the reassignment of the Administrative Law Judge (“ALJ”) assigned to the case. As a result of this delay, Southwest filed a motion during the first quarter of 2003 requesting authorization to establish a memorandum account to track the related revenue shortfall between the existing and proposed rates in the general rate case filing. This motion was approved, effective May 2003. In October 2003, the ALJ rendered a draft decision (“proposed decision” or “PD”) on the general rate case. The PD was modified in February 2004. If approved as modified, the PD would increase rates by about 60 percent of the 2003 amount filed for and provide for attrition increases beginning in 2004. Southwest filed comments largely in support of the PD. In January 2004, an alternate decision (“AD”) from one of the commissioners was received, reducing the rate increase in southern California as proposed in the PD by $2 million, with no significant change to northern California. In addition, the AD proposed a disallowance of $12.2 million in gas costs. Southwest filed comments vehemently opposed to the AD. The general rate case is on the agenda for mid-March; however, management can not determine which, if any, of the proposed or alternate decisions will be approved.
FERC Jurisdiction. In July 1996, Paiute Pipeline Company, a wholly owned subsidiary of the Company, filed its most recent general rate case with the Federal Energy Regulatory Commission (“FERC”). The FERC authorized a general rate increase effective January 1997. The timing of Paiute’s next general rate case filing has not been determined.
southwest gas 2003 annual report
PAGE 28
management’s discussion and analysis of
financial condition and results of operations
PGA FILINGS
The rate schedules in all of the service territories contain PGA clauses, which permit adjustments to rates as the cost of purchased gas changes. In Arizona, Southwest adjusts rates monthly for changes in purchased gas costs, within pre-established limits. In California, a monthly gas cost adjustment based on forecasted monthly prices is utilized. Monthly adjustments are designed to provide a more timely recovery of gas costs and to send appropriate pricing signals to customers. In Nevada, tariffs provide for annual adjustment dates for changes in purchased gas costs. In addition, Southwest may request to adjust rates more often, if conditions warrant. Filings to change rates in accordance with PGA clauses are subject to audit by state regulatory commission staffs. PGA changes impact cash flows but have no direct impact on profit margin. Southwest had the following outstanding PGA balances receivable/(payable) at the end of its two most recent fiscal years (millions of dollars):
2003 | 2002 | |||||||
Arizona | $ (5.8 | ) | $ (24.0 | ) | ||||
Northern Nevada | 1.7 | 8.3 | ||||||
Southern Nevada | 5.1 | (21.9 | ) | |||||
California | 8.2 | 10.9 | ||||||
$ | 9.2 | $ | (26.7 | ) | ||||
Nevada PGA Filings. In June 2003, Southwest made its annual PGA filing with the PUCN. Southwest requested a change to a monthly PGA mechanism, rather than annual, to reduce volatility in rate changes. Effective in December 2003, the PUCN approved an increase of $25.5 million, or 12.3 percent, for customers in southern Nevada and a decrease of $8.6 million, or 10.2 percent, in northern Nevada. The monthly adjustment mechanism proposed in the annual filing was not adopted. As a result of increases in gas costs experienced since the annual filing in June 2003 (in addition to projected continued increases), an out-of-cycle filing was made in December 2003. This filing requested increases of $59.8 million, or 25.5 percent, in southern Nevada and $16.7 million, or 22.1 percent, in northern Nevada. In January 2004, the PUCN approved the elimination of a credit surcharge, resulting in an interim increase of 5.5 percent in southern Nevada and 4.8 percent in northern Nevada beginning in February 2004. A final decision on the PGA filing is expected in the second quarter of 2004.
OTHER FILINGS
Since November 1999, the Federal Energy Regulatory Commission has been examining capacity allocation issues on the El Paso system in several proceedings. This examination resulted in a series of orders by the FERC in which all of the major full requirements transportation service agreements on the El Paso system, including the agreement by which Southwest obtained the transportation of gas supplies to its Arizona service areas, were converted to contract demand-type service agreements, with fixed maximum service limits, effective September 2003. At that time, all of the transportation capacity on the system was allocated among the shippers. In order to help ensure that the converting full requirements shippers would have adequate capacity to meet their needs, El Paso was authorized to expand the capacity on its system by adding compression.
The FERC is continuing to examine issues related to the implementation of the full requirements conversion. Petitions for judicial review of the FERC’s orders mandating the conversion have been filed.
southwest gas 2003 annual report
PAGE 29
management’s discussion and analysis of
financial condition and results of operations
Management believes that it is difficult to predict the ultimate outcome of the proceedings or the impact of the FERC action on Southwest. Southwest has had adequate capacity for its customers needs during the 2003/2004 heating season to date and management believes adequate capacity exists for the remainder of the heating season. Additional costs may be incurred to acquire capacity in the future as a result of the FERC order. However, it is anticipated that any additional costs will be collected from customers through the PGA mechanism.
CAPITAL RESOURCES AND LIQUIDITY
The capital requirements and resources of the Company generally are determined independently for the natural gas operations and construction services segments. Each business activity is generally responsible for securing its own financing sources. The capital requirements and resources of the construction services segment are not material to the overall capital requirements and resources of the Company.
Southwest continues to experience significant customer growth. This growth has required significant capital outlays for new transmission and distribution plant, to keep up with consumer demand. During the three-year period ended December 31, 2003, total gas plant increased from $2.4 billion to $3 billion, or at an annual rate of nine percent. Customer growth was the primary reason for the plant increase as Southwest added 194,000 net new customers (including BMG) during the three-year period.
During 2003, capital expenditures for the natural gas operations segment were $228 million. Approximately 72 percent of these current-period expenditures represented new construction and the balance represented costs associated with routine replacement of existing transmission, distribution, and general plant. Cash flows from operating activities of Southwest (net of dividends) provided $159 million of the required capital resources pertaining to total construction expenditures in 2003. The remainder was provided from external financing activities.
asset purchases
In October 2003, the Company completed the purchase of BMG, a gas utility serving portions of Carefree, North Scottsdale, North Phoenix, Cave Creek, and Page, Arizona. The Company paid approximately $24 million for BMG. BMG has approximately 9,000 natural gas customers in a rapidly growing area north of Phoenix and about 2,500 propane customers. The Company plans to sell the propane operations.
2003 financing activity
In March 2003, the Company issued several series of Clark County, Nevada Industrial Development Revenue Bonds (“IDRBs”) totaling $165 million, due 2038. Of this total, variable-rate IDRBs ($50 million 2003 Series A and $50 million 2003 Series B) were used to refinance the $100 million 7.50% 1992 Series B, fixed-rate IDRBs due 2032. At December 31, 2003, the effective interest rate including all fees on the new Series A and Series B IDRBs was 2.66%. The $30 million 7.30% 1992 Series A, fixed-rate IDRBs due 2027 was refinanced with $30 million 5.45% 2003 Series C fixed-rate IDRBs. An incremental $35 million ($20 million 3.35% 2003 Series D and $15 million 5.80% Series E fixed-rate IDRBs) was used to finance construction expenditures in southern Nevada during the first and second quarters of 2003. The Series C and Series E were set with an initial interest rate period of 10 years, while the Series D has an initial interest rate period of 18 months. After the initial interest rate periods, the Series C, D, and E interest rates will be reset at then prevailing market rates for periods not to exceed the maturity date of March 1, 2038.
southwest gas 2003 annual report
PAGE 30
management’s discussion and analysis of
financial condition and results of operations
The 2003 Series A and Series B IDRBs described above are supported by two letters of credit totaling $101.7 million, which expire in March 2006. These IDRBs are set at weekly rates and the letters of credit support the payment of principal or a portion of the purchase price corresponding to the principal of the IDRBs while in the weekly rate mode.
In June 2003, the Company filed a registration statement on Form S-3 for an incremental $100 million of various securities with the Securities and Exchange Commission (“SEC”) and to revise $200 million of securities previously registered to provide additional flexibility in the types of securities available for issuance. After the issuance of the preferred securities described in the following paragraph, the Company has a total of $200 million in securities registered with the SEC which are available for future financing needs.
In August 2003, Southwest Gas Capital II, a wholly owned subsidiary and financing trust, issued $100 million of 7.70% Preferred Trust Securities. A portion of the net proceeds from the issuance of the Preferred Trust Securities was used to complete the redemption of the 9.125% Trust Originated Preferred Securities effective September 2003 at a redemption price of $25 per Preferred Security, totaling $60 million plus accrued interest of $1.3 million. For more information, including the accounting treatment, see Note 5 – Preferred Securities.
In October 2003, a $55.3 million letter of credit, which supports the City of Big Bear $50 million tax-exempt Series A IDRBs, due 2028, was renewed for a three-year period expiring in October 2006.
In July 2003, the Company registered 1.5 million shares of common stock with the SEC for issuance under the Southwest Gas Corporation 2002 Stock Incentive Plan. In December 2003, the Company registered 600,000 shares of common stock with the SEC for issuance under the Southwest Gas Corporation Employees’ Investment Plan.
2004 construction expenditures and financing
In March 2002, the Job Creation and Worker Assistance Act of 2002 (“2002 Act”) was signed into law. The 2002 Act provided a three-year, 30 percent bonus depreciation deduction for businesses. The Jobs and Growth Tax Relief Reconciliation Act of 2003 (“2003 Act”), signed into law in May 2003, provides for enhanced and extended bonus tax depreciation. The 2003 Act increased the bonus depreciation rate to 50 percent for qualifying property placed in service after May 2003 and, generally, before January 2005. Southwest estimates the 2002 and 2003 Acts bonus depreciation deductions will defer the payment of $35 million of federal income taxes during 2004.
Southwest estimates construction expenditures during the three-year period ending December 31, 2006 will be approximately $690 million. Of this amount, $233 million are expected to be incurred in 2004. During the three-year period, cash flow from operating activities including the impacts of the Acts (net of dividends) is estimated to fund approximately 80 percent of the gas operations’ total construction expenditures. The Company expects to raise $50 million to $55 million from its Dividend Reinvestment and Stock Purchase Plan (“DRSPP”). The remaining cash requirements are expected to be provided by other external financing sources. The timing, types, and amounts of these additional external financings will be dependent on a number of factors, including conditions in the capital markets, timing and amounts of rate relief, growth levels in Southwest service areas, and earnings. These external financings may include the issuance of both debt and equity securities, bank and other short-term borrowings, and other forms of financing.
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management’s discussion and analysis of
financial condition and results of operations
off balance sheet arrangements
All Company debt is recorded on its balance sheets. The Company has long-term operating leases, which are described in Note 2 – Utility Plant of the Notes to Consolidated Financial Statements. No debt instruments have credit triggers or other clauses that result in default if Company bond ratings are lowered by rating agencies. Certain Company debt instruments contain customary leverage, net worth and other covenants, and securities ratings covenants that, if set in motion, would increase financing costs. To date, the Company has not incurred any increased financing costs as a result of these covenants.
Southwest has fixed-price gas purchase contracts, which are considered normal purchases occurring in the ordinary course of business. These gas purchase contracts are entered into annually to mitigate market price volatility. The Company does not currently utilize other stand-alone derivative instruments for speculative purposes or for hedging and does not have foreign currency exposure. None of the Company’s long-term financial instruments or other contracts are derivatives that are marked to market, or contain embedded derivatives with significant mark-to-market value.
contractual obligations
Obligations under long-term debt, gas purchase obligations and non-cancelable operating leases at December 31, 2003 were as follows:
CONTRACTUAL OBLIGATIONS
(millions of dollars) | PAYMENTS DUE BY PERIOD | ||||||||||||||
TOTAL | 2004 | 2005-2006 | 2007-2008 | THEREAFTER | |||||||||||
Short-term debt (Note 7) | $ | 52 | $ | 52 | $ | — | $ | — | $ | — | |||||
Subordinated debentures to Southwest | 103 | — | — | — | 103 | ||||||||||
Long-term debt (Note 6) | 1,121 | 6 | 204 | 43 | 868 | ||||||||||
Operating leases (Note 2) | 47 | 8 | 10 | 8 | 21 | ||||||||||
Gas purchase obligations (a) | 218 | 170 | 48 | — | — | ||||||||||
Pipeline capacity (b) | 551 | 69 | 137 | 132 | 213 | ||||||||||
Other commitments | 8 | 4 | 4 | — | — | ||||||||||
Total | $ | 2,100 | $ | 309 | $ | 403 | $ | 183 | $ | 1,205 | |||||
(a) Includes fixed price and variable rate gas purchase contracts covering approximately 99 million dekatherms. Fixed price contracts range in price from $3.70 to $5.84 per dekatherm. Variable price contracts reflect minimum contractual obligations.
(b) Southwest has pipeline capacity contracts for firm transportation service, both on a short- and long-term basis, with several companies (primarily El Paso Natural Gas Company and Kern River Gas Transmission Company) for all of its service territories. Southwest also has interruptible contracts in place that allow additional capacity to be acquired should an unforeseen need arise. Costs associated with these pipeline capacity contracts are a component of the cost of gas sold and are recovered from customers primarily through the PGA mechanism.
Estimated pension funding for 2004 is $14 million.
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management’s discussion and analysis of
financial condition and results of operations
liquidity
Liquidity refers to the ability of an enterprise to generate adequate amounts of cash to meet its cash requirements. Several general factors that could significantly affect capital resources and liquidity in future years include inflation, growth in the economy, changes in income tax laws, changes in the ratemaking policies of regulatory commissions, interest rates, variability of natural gas prices, and the level of Company earnings.
Since the winter of 2000-2001, the price of natural gas has varied widely. Southwest customers have benefited from the fixed prices associated with term contracts in place during 2003. These contracts are generally of short duration (less than one year) and cover about half of Southwest’s supply needs. Southwest enters into new contracts annually to replace those that are expiring to help mitigate price volatility. Remaining needs will be covered with the purchase of natural gas on the spot market and are subject to market fluctuations. Over the next few years, continued strong growth in natural gas demand and limited supply increases indicate prices for natural gas will remain volatile. Southwest continues to pursue all available sources to maintain the balance between a low cost and reliable supply of natural gas for its customers. All incremental costs are expected to be included in the PGA mechanism for recovery from customers in each rate jurisdiction.
The rate schedules in all of the service territories of Southwest contain PGA clauses which permit adjustments to rates as the cost of purchased gas changes. The PGA mechanism allows Southwest to change the gas cost component of the rates charged to its customers to reflect increases or decreases in the price expected to be paid to its suppliers and companies providing interstate pipeline transportation service. On an interim basis, Southwest generally defers over or under collections of gas costs to PGA balancing accounts. In addition, Southwest uses this mechanism to either refund amounts over-collected or recoup amounts under-collected as compared to the price paid for natural gas during the period since the last PGA rate change went into effect. At December 31, 2003, the combined balances in PGA accounts totaled an under-collection of $9.2 million versus an over-collection of $27 million at December 31, 2002. See PGA Filings for more information on recent regulatory filings. Southwest utilizes short-term borrowings to temporarily finance under-collected PGA balances. Southwest has a total short-term borrowing capacity of $150 million (with $98 million available at December 31, 2003), which the Company believes is adequate to meet anticipated needs.
PGA changes affect cash flows but have no direct impact on profit margin. In addition, since Southwest is permitted to accrue interest on PGA balances, the cost of incremental, PGA-related short-term borrowings will be offset, and there should be no material negative impact to earnings. However, gas cost deferrals and recoveries can impact comparisons between periods of individual income statement components. These include Gas operating revenues, Net cost of gas sold, Net interest deductions and Other income (deductions).
The Company has a common stock dividend policy which states that common stock dividends will be paid at a prudent level that is within the normal dividend payout range for its respective businesses, and that the dividend will be established at a level considered sustainable in order to minimize business risk and maintain a strong capital structure throughout all economic cycles. The quarterly common stock dividend was 20.5 cents per share throughout 2003. The dividend of 20.5 cents per share has been paid quarterly since September 1994.
security ratings
Securities ratings issued by nationally recognized ratings agencies provide a method for determining the credit worthiness of an issuer. Company debt ratings are important because long-term debt constitutes a significant portion of total capitalization. These debt ratings are a factor considered by lenders when determining the cost of debt for the Company (i.e., the better the rating, the lower the cost to borrow funds).
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management’s discussion and analysis of
financial condition and results of operations
Since January 1997, Moody’s Investors Service, Inc. (“Moody’s”) has rated Company unsecured long-term debt at Baa2. Moody’s debt ratings range from Aaa (best quality) to C (lowest quality). Moody’s applies a Baa2 rating to obligations which are considered medium grade obligations (i.e., they are neither highly protected nor poorly secured).
The Company’s unsecured long-term debt rating from Fitch, Inc. (“Fitch”) is BBB. Fitch debt ratings range from AAA (highest credit quality) to D (defaulted debt obligation). The Fitch rating of BBB indicates a credit quality that is considered prudent for investment.
The Company’s unsecured long-term debt rating from Standard and Poor’s Ratings Services (“S&P”) is BBB-. S&P debt ratings range from AAA (highest rating possible) to D (obligation is in default). The S&P rating of BBB- indicates the debt is regarded as having an adequate capacity to pay interest and repay principal.
A securities rating is not a recommendation to buy, sell, or hold a security and is subject to change or withdrawal at any time by the rating agency.
inflation
Results of operations are impacted by inflation. Natural gas, labor, and construction costs are the categories most significantly impacted by inflation. Changes to cost of gas are generally recovered through PGA mechanisms and do not significantly impact net earnings. Labor is a component of the cost of service, and construction costs are the primary component of rate base. In order to recover increased costs, and earn a fair return on rate base, general rate cases are filed by Southwest, when deemed necessary, for review and approval by regulatory authorities. Regulatory lag, that is, the time between the date increased costs are incurred and the time such increases are recovered through the ratemaking process, can impact earnings. See Rates and Regulatory Proceedings for a discussion of recent rate case proceedings.
RESULTS OF CONSTRUCTION SERVICES
(thousands of dollars) | |||||||||
YEAR ENDED DECEMBER 31, | 2003 | 2002 | 2001 | ||||||
Construction revenues | $ | 196,651 | $ | 205,009 | $ | 203,586 | |||
Cost of construction | 184,290 | 191,561 | 189,429 | ||||||
Gross profit | 12,361 | 13,448 | 14,157 | ||||||
General and administrative expenses | 5,543 | 5,542 | 5,026 | ||||||
Operating income | 6,818 | 7,906 | 9,131 | ||||||
Other income (expense) | 1,290 | 1,221 | 871 | ||||||
Interest expense | 855 | 1,466 | 1,985 | ||||||
Income before income taxes | 7,253 | 7,661 | 8,017 | ||||||
Income tax expense | 2,962 | 2,924 | 3,487 | ||||||
Contribution to consolidated net income | $ | 4,291 | $ | 4,737 | $ | 4,530 | |||
2003 vs. 2002
The 2003 contribution to consolidated net income from construction services decreased $446,000 from the prior year. The decrease was primarily due to a decline in construction revenues and an insurance settlement, partially offset by lower interest expense.
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management’s discussion and analysis of
financial condition and results of operations
Revenues decreased $8.4 million due to a reduced workload in some operating areas, the completion of certain projects, and the non-renewal of two long-term contracts. Cost of construction includes a one-time $1.3 million charge for an unfavorable insurance settlement. Interest expense declined $611,000 as a result of the refinancing of long-term debt to take advantage of lower interest rates.
2002 vs. 2001
The 2002 contribution to consolidated net income from construction services increased $207,000 from the prior year. The increase was primarily due to a decline in Income tax expense and an increase in Other income. Revenues remained relatively constant, while the gross profit margin percentage decreased slightly.
Gross profit decreased $709,000 because of the absorption of significant increases in insurance costs. Other income in 2001 included $400,000 of goodwill amortization that was not included in 2002 due to the adoption of a new accounting pronouncement. General and administrative expenses increased by $516,000 due to increased labor costs and additional depreciation related to a new computer system. Interest expense declined as a result of the refinancing of long-term debt to take advantage of lower interest rates. Income tax expense decreased largely as a result of a $274,000 tax credit in the state of Arizona.
RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
In January 2003, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 46 “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51” (“FIN 46”) effective July 2003. This Interpretation of Accounting Research Bulletin No. 51 “Consolidated Financial Statements,” addresses consolidation by business enterprises of variable interest entities. FIN 46 explains how to identify variable interest entities and how an enterprise assesses its interests in a variable interest entity to decide whether to consolidate that entity. Southwest Gas Capital II (“Trust II”), a wholly owned subsidiary, was created by the Company to issue preferred trust securities for the benefit of the Company. (See Note 5 of the Notes to Consolidated Financial Statements for additional information.) Trust II, the issuer of the preferred trust securities, meets the definition of a variable interest entity.
Although the Company owns 100 percent of the common voting securities of Trust II, under current interpretation of FIN 46, the Company is not considered the primary beneficiary of this trust and therefore Trust II is not consolidated. The adoption of FIN 46 results in the Company reflecting a liability to Trust II, which under the prior accounting treatment would have been eliminated in consolidation, instead of to the holders of the preferred trust securities. As a result, payments and amortizations associated with the liability are classified on the consolidated statements of income as Net interest deductions on subordinated debentures.
APPLICATION OF CRITICAL ACCOUNTING POLICIES
A critical accounting policy is one which is very important to the portrayal of the financial condition and results of a company, and requires the most difficult, subjective, or complex judgments of management. The need to make estimates about the effect of items that are uncertain is what makes these judgments difficult, subjective, and/or complex. Management makes subjective judgments about the accounting and regulatory treatment of many items. The following are examples of accounting policies that are critical to the financial statements of the Company. For more information regarding the significant accounting policies of the Company, see Note 1 – Summary of Significant Accounting Policies.
n | Natural gas operations are subject to the regulation of the Arizona Corporation Commission, the Public Utilities Commission of Nevada, the California Public Utilities Commission, and the Federal Energy Regulatory Commission. The |
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management’s discussion and analysis of
financial condition and results of operations
accounting policies of the Company conform to generally accepted accounting principles applicable to rate-regulated enterprises (including SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation”) and reflect the effects of the ratemaking process. As such, the Company is allowed to defer as regulatory assets, costs that otherwise would be expensed if it is probable that future recovery from customers will occur. If rate recovery is no longer probable, due to competition or the actions of regulators, the Company is required to write-off the related regulatory asset. Refer to Note 4 – Regulatory Assets and Liabilities for a list of regulatory assets. |
n | The income tax calculations of the Company require estimates due to regulatory differences between the multiple states in which the Company operates, and future tax rate changes. The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A change in the regulatory treatment or significant changes in tax-related estimates, assumptions, or enacted tax rates could have a material impact on the financial position and results of operations of the Company. |
n | Depreciation is computed at composite rates considered sufficient to amortize costs over the estimated remaining lives of assets, and includes adjustments for the cost of removal, and salvage value. Depreciation studies are performed periodically and prospective changes in rates are estimated to make up for past differences. These studies are reviewed and approved by the appropriate regulatory agency. Changes in estimates of depreciable lives or changes in depreciation rates mandated by regulations could affect the results of operations of the Company in periods subsequent to the change. |
n | In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which was effective for fiscal years beginning after June 15, 2002. SFAS No. 143 establishes accounting standards for recognition and measurement of liabilities for asset retirement obligations and the associated asset retirement costs. The Company adopted the provisions of SFAS No. 143 as of January 1, 2003. |
In accordance with approved regulatory practices, the depreciation expense for Southwest includes a component to recover removal costs associated with utility plant retirements. In accordance with the SEC’s position on presentation of these amounts, management has reclassified $68 million and $55 million, as of December 31, 2003 and 2002, respectively, of estimated removal costs from accumulated depreciation to accumulated removal costs (in the liabilities section of the balance sheet). |
Under utility accounting, all plant is assumed to be fully depreciated upon retirement. However, retirements often occur earlier than the average service life of the plant group. Accumulated depreciation has a historical mix of credits (depreciation amounts designed to recover plant investment and net removal costs) and debits (charges for retirements and actual costs of removal). The actual amount of net removal costs recorded as credits has never been tracked by the Company. The estimate of the calculated cost of removal embedded in accumulated depreciation employed various assumptions including average service lives and historical depreciation rates. Variations in the assumptions utilized would result in a range of accumulated removal costs that would vary significantly from the amount estimated above. |
Management believes that regulation and the effects of regulatory accounting have the most significant impact on the financial statements. When Southwest files rate cases, capital assets, costs, and gas purchasing practices are subject to review, and disallowances can occur. Regulatory disallowances in the past have not been frequent but have on occasion been significant to the operating results of the Company.
FORWARD-LOOKING STATEMENTS
This annual report contains statements which constitute “forward-looking statements” within the meaning of the Securities Litigation Reform Act of 1995 (“Reform Act”). All statements other than statements of historical fact included or incorporated by reference in this annual report are forward-looking statements, including, without limitation, statements regarding the Company’s plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions. The words “may,” “will,” “should,” “could,” “expect,” “plan,” “anticipate,” “believe,” “estimate,” “predict,” “continue,” and similar words and expressions are generally used and intended to identify forward-looking statements. All forward-looking statements are intended to be subject to the safe harbor protection provided by the Reform Act.
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management’s discussion and analysis of
financial condition and results of operations
A number of important factors affecting the business and financial results of the Company could cause actual results to differ materially from those stated in the forward-looking statements. These factors include, but are not limited to, the impact of weather variations on customer usage, customer growth rates, changes in natural gas prices, our ability to recover costs through our PGA mechanism, the effects of regulation/deregulation, the timing and amount of rate relief, changes in gas procurement practices, changes in capital requirements and funding, the impact of conditions in the capital markets on financing costs, changes in construction expenditures and financing, changes in operations and maintenance expenses, changes in pipeline capacity for the transportation of gas and related costs, acquisitions and management’s plans related thereto, competition and our ability to raise capital in external financings or through our DRSPP. In addition, the Company can provide no assurance that its discussions regarding certain trends relating to its financing, operations and maintenance expenses will continue in future periods. For additional information on the risks associated with the Company’s business, see Item 1. Business – Company Risk Factors in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003.
All forward-looking statements in this annual report are made as of the date hereof, based on information available to the Company as of the date hereof, and the Company assumes no obligation to update or revise any of its forward-looking statements even if experience or future changes show that the indicated results or events will not be realized. We caution you not to unduly rely on any forward-looking statement(s).
COMMON STOCK PRICE AND DIVIDEND INFORMATION
2003 | 2002 | DIVIDENDS PAID | ||||||||||||||||
HIGH | LOW | HIGH | LOW | 2003 | 2002 | |||||||||||||
First quarter | $ | 23.64 | $ | 19.30 | $ | 25.35 | $ | 21.80 | $ | 0.205 | $ | 0.205 | ||||||
Second quarter | 22.45 | 19.74 | 24.99 | 22.60 | 0.205 | 0.205 | ||||||||||||
Third quarter | 23.49 | 20.14 | 24.75 | 18.10 | 0.205 | 0.205 | ||||||||||||
Fourth quarter | 23.48 | 22.04 | 23.63 | 19.82 | 0.205 | 0.205 | ||||||||||||
$ | 0.820 | $ | 0.820 | |||||||||||||||
The principal markets on which the common stock of the Company is traded are the New York Stock Exchange and the Pacific Exchange. At March 1, 2004, there were 23,259 holders of record of common stock and the market price of the common stock was $23.45.
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southwest gas corporation
consolidated balance sheets
(thousands of dollars, except par value) | ||||||||
DECEMBER 31, | 2003 | 2002 | ||||||
ASSETS | ||||||||
UTILITY PLANT: | ||||||||
Gas plant | $ | 3,035,969 | $ | 2,779,960 | ||||
Less: accumulated depreciation | (896,309 | ) | (814,908 | ) | ||||
Acquisition adjustments, net | 2,533 | 2,714 | ||||||
Construction work in progress | 33,543 | 66,693 | ||||||
Net utility plant (Note 2) | 2,175,736 | 2,034,459 | ||||||
Other property and investments | 87,443 | 87,391 | ||||||
CURRENT ASSETS: | ||||||||
Cash and cash equivalents | 17,183 | 19,392 | ||||||
Accounts receivable, net of allowances (Note 3) | 126,783 | 130,695 | ||||||
Accrued utility revenue | 66,700 | 65,073 | ||||||
Deferred income taxes (Note 10) | 6,914 | 3,084 | ||||||
Deferred purchased gas costs (Note 4) | 9,151 | — | ||||||
Prepaids and other current assets (Note 4) | 54,356 | 43,524 | ||||||
Total current assets | 281,087 | 261,768 | ||||||
Deferred charges and other assets (Note 4) | 63,840 | 49,310 | ||||||
Total assets | $ | 2,608,106 | $ | 2,432,928 | ||||
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southwest gas corporation
consolidated balance sheets
(thousands of dollars, except par value) | ||||||
DECEMBER 31, | 2003 | 2002 | ||||
CAPITALIZATION AND LIABILITIES | ||||||
CAPITALIZATION: | ||||||
Common stock, $1 par (authorized – 45,000,000 shares; issued | $ | 35,862 | $ | 34,919 | ||
Additional paid-in capital | 510,521 | 487,788 | ||||
Retained earnings | 84,084 | 73,460 | ||||
Total equity | 630,467 | 596,167 | ||||
Mandatorily redeemable preferred trust securities (Note 5) | — | 60,000 | ||||
Subordinated debentures due to Southwest Gas Capital II (Note 5) | 100,000 | — | ||||
Long-term debt, less current maturities (Note 6) | 1,121,164 | 1,092,148 | ||||
Total capitalization | 1,851,631 | 1,748,315 | ||||
Commitments and contingencies (Note 8) | ||||||
CURRENT LIABILITIES: | ||||||
Current maturities of long-term debt (Note 6) | 6,435 | 8,705 | ||||
Short-term debt (Note 7) | 52,000 | 53,000 | ||||
Accounts payable | 110,114 | 88,309 | ||||
Customer deposits | 44,290 | 34,313 | ||||
Income taxes payable, net | — | 10,969 | ||||
Accrued general taxes | 32,466 | 28,400 | ||||
Accrued interest | 19,665 | 21,137 | ||||
Deferred purchased gas costs (Note 4) | — | 26,718 | ||||
Other current liabilities | 45,442 | 41,630 | ||||
Total current liabilities | 310,412 | 313,181 | ||||
DEFERRED INCOME TAXES AND OTHER CREDITS: | ||||||
Deferred income taxes and investment tax credits (Note 10) | 277,332 | 229,358 | ||||
Taxes payable | 6,661 | — | ||||
Accumulated removal costs (Note 4) | 68,000 | 55,000 | ||||
Other deferred credits (Note 4) | 94,070 | 87,074 | ||||
Total deferred income taxes and other credits | 446,063 | 371,432 | ||||
Total capitalization and liabilities | $ | 2,608,106 | $ | 2,432,928 | ||
The accompanying notes are an integral part of these statements.
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southwest gas corporation
consolidated statements of income
(in thousands, except per share amounts) | ||||||||||||
YEAR ENDED DECEMBER 31, | 2003 | 2002 | 2001 | |||||||||
OPERATING REVENUES: | ||||||||||||
Gas operating revenues | $ | 1,034,353 | $ | 1,115,900 | $ | 1,193,102 | ||||||
Construction revenues | 196,651 | 205,009 | 203,586 | |||||||||
Total operating revenues | 1,231,004 | 1,320,909 | 1,396,688 | |||||||||
OPERATING EXPENSES: | ||||||||||||
Net cost of gas sold | 482,503 | 563,379 | 677,547 | |||||||||
Operations and maintenance | 266,862 | 264,188 | 253,026 | |||||||||
Depreciation and amortization | 136,439 | 130,210 | 118,448 | |||||||||
Taxes other than income taxes | 35,910 | 34,565 | 32,780 | |||||||||
Construction expenses | 174,185 | 182,068 | 180,904 | |||||||||
Total operating expenses | 1,095,899 | 1,174,410 | 1,262,705 | |||||||||
Operating income | 135,105 | 146,499 | 133,983 | |||||||||
OTHER INCOME AND (EXPENSES): | ||||||||||||
Net interest deductions | (77,106 | ) | (79,971 | ) | (80,731 | ) | ||||||
Net interest deductions on subordinated debentures (Note 5) | (2,680 | ) | — | — | ||||||||
Preferred securities distributions (Note 5) | (4,180 | ) | (5,475 | ) | (5,475 | ) | ||||||
Other income (deductions) | 4,245 | 4,329 | 8,964 | |||||||||
Total other income and (expenses) | (79,721 | ) | (81,117 | ) | (77,242 | ) | ||||||
Income before income taxes | 55,384 | 65,382 | 56,741 | |||||||||
Income tax expense (Note 10) | 16,882 | 21,417 | 19,585 | |||||||||
Net income | $ | 38,502 | $ | 43,965 | $ | 37,156 | ||||||
Basic earnings per share (Note 12) | $ | 1.14 | $ | 1.33 | $ | 1.16 | ||||||
Diluted earnings per share (Note 12) | $ | 1.13 | $ | 1.32 | $ | 1.15 | ||||||
Average number of common shares outstanding | 33,760 | 32,953 | 32,122 | |||||||||
Average shares outstanding (assuming dilution) | 34,041 | 33,233 | 32,398 |
The accompanying notes are an integral part of these statements.
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southwest gas corporation
consolidated statements of cash flows
(thousands of dollars) | ||||||||||||
YEAR ENDED DECEMBER 31, | 2003 | 2002 | 2001 | |||||||||
CASH FLOW FROM OPERATING ACTIVITIES: | ||||||||||||
Net income | $ | 38,502 | $ | 43,965 | $ | 37,156 | ||||||
ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH PROVIDED BY OPERATING ACTIVITIES: | ||||||||||||
Depreciation and amortization | 136,439 | 130,210 | 118,448 | |||||||||
Deferred income taxes | 44,144 | (15,684 | ) | (11,175 | ) | |||||||
CHANGES IN CURRENT ASSETS AND LIABILITIES: | ||||||||||||
Accounts receivable, net of allowances | 4,416 | 24,687 | (19,773 | ) | ||||||||
Accrued utility revenue | (1,627 | ) | (1,300 | ) | (5,900 | ) | ||||||
Deferred purchased gas costs | (35,981 | ) | 110,219 | 8,563 | ||||||||
Accounts payable | 21,586 | (20,858 | ) | (85,512 | ) | |||||||
Accrued taxes | (386 | ) | 33,997 | 18,766 | ||||||||
Other current assets and liabilities | 1,692 | 4,763 | 34,051 | |||||||||
Other | (1,009 | ) | (11,525 | ) | 28,128 | |||||||
Net cash provided by operating activities | 207,776 | 298,474 | 122,752 | |||||||||
CASH FLOW FROM INVESTING ACTIVITIES: | ||||||||||||
Construction expenditures and property additions | (240,671 | ) | (282,851 | ) | (265,580 | ) | ||||||
Other (Note 14) | (18,215 | ) | 23,985 | 4,318 | ||||||||
Net cash used in investing activities | (258,886 | ) | (258,866 | ) | (261,262 | ) | ||||||
CASH FLOW FROM FINANCING ACTIVITIES: | ||||||||||||
Issuance of common stock, net | 21,290 | 18,174 | 17,061 | |||||||||
Dividends paid | (27,685 | ) | (27,009 | ) | (26,323 | ) | ||||||
Issuance of subordinated debentures, net | 96,312 | — | — | |||||||||
Issuance of long-term debt, net | 159,997 | 206,161 | 213,026 | |||||||||
Retirement of long-term debt, net | (140,013 | ) | (210,028 | ) | (14,723 | ) | ||||||
Retirement of preferred securities | (60,000 | ) | — | — | ||||||||
Change in short-term debt | (1,000 | ) | (40,000 | ) | (38,000 | ) | ||||||
Net cash provided by (used in) financing activities | 48,901 | (52,702 | ) | 151,041 | ||||||||
Change in cash and cash equivalents | (2,209 | ) | (13,094 | ) | 12,531 | |||||||
Cash at beginning of period | 19,392 | 32,486 | 19,955 | |||||||||
Cash at end of period | $ | 17,183 | $ | 19,392 | $ | 32,486 | ||||||
SUPPLEMENTAL INFORMATION: | ||||||||||||
Interest paid, net of amounts capitalized | $ | 78,561 | $ | 76,867 | $ | 74,032 | ||||||
Income taxes paid (received), net | $ | (26,733 | ) | $ | 1,797 | $ | 13,186 | |||||
The accompanying notes are an integral part of these statements.
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southwest gas corporation
consolidated statements of stockholders’ equity
(in thousands, except per share amounts) | |||||||||||||||||
COMMON STOCK | |||||||||||||||||
SHARES | AMOUNT | ADDITIONAL PAID-IN CAPITAL | RETAINED EARNINGS | TOTAL | |||||||||||||
DECEMBER 31, 2000 | 31,710 | $ | 33,340 | $ | 454,132 | $ | 45,995 | $ | 533,467 | ||||||||
Common stock issuances | 783 | 783 | 16,278 | 17,061 | |||||||||||||
Net income | 37,156 | 37,156 | |||||||||||||||
Dividends declared | |||||||||||||||||
Common: $0.82 per share | (26,484 | ) | (26,484 | ) | |||||||||||||
DECEMBER 31, 2001 | 32,493 | 34,123 | 470,410 | 56,667 | 561,200 | ||||||||||||
Common stock issuances | 796 | 796 | 17,378 | 18,174 | |||||||||||||
Net income | 43,965 | 43,965 | |||||||||||||||
Dividends declared | |||||||||||||||||
Common: $0.82 per share | (27,172 | ) | (27,172 | ) | |||||||||||||
DECEMBER 31, 2002 | 33,289 | 34,919 | 487,788 | 73,460 | 596,167 | ||||||||||||
Common stock issuances | 943 | 943 | 20,347 | 21,290 | |||||||||||||
Net income | 38,502 | 38,502 | |||||||||||||||
Other | 2,386 | 2,386 | |||||||||||||||
Dividends declared Common: $0.82 per share | (27,878 | ) | (27,878 | ) | |||||||||||||
DECEMBER 31, 2003 | 34,232 | * | $ | 35,862 | $ | 510,521 | $ | 84,084 | $ | 630,467 | |||||||
* At December 31, 2003, 882,000 common shares were registered and available for issuance under provisions of the Employee Investment Plan and the Dividend Reinvestment and Stock Purchase Plan. In addition, 2.5 million common shares are registered for issuance upon the exercise of options granted under the Stock Incentive Plan (see Note 9).
The accompanying notes are an integral part of these statements.
southwest gas 2003 annual report
PAGE 42
notes to consolidated financial statements
NOTE 1
summary of significant accounting policies
Nature of Operations. Southwest Gas Corporation (the “Company”) is comprised of two segments: natural gas operations (“Southwest” or the “natural gas operations” segment) and construction services. Southwest purchases, transports, and distributes natural gas to customers in portions of Arizona, Nevada, and California. The public utility rates, practices, facilities, and service territories of Southwest are subject to regulatory oversight. The timing and amount of rate relief can materially impact results of operations. Natural gas sales are seasonal, peaking during the winter months. Variability in weather from normal temperatures can materially impact results of operations. Natural gas purchases and the timing of related recoveries can materially impact liquidity. Northern Pipeline Construction Co. (“NPL” or the “construction services” segment), a wholly owned subsidiary, is a full-service underground piping contractor that provides utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.
Basis of Presentation. The Company follows generally accepted accounting principles (“GAAP”) in accounting for all of its businesses. Accounting for the natural gas utility operations conforms with GAAP as applied to regulated companies and as prescribed by federal agencies and the commissions of the various states in which the utility operates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Consolidation. The accompanying financial statements are presented on a consolidated basis and include the accounts of Southwest Gas Corporation and all subsidiaries, except for Southwest Gas Capital II (see Note 5). All significant intercompany balances and transactions have been eliminated with the exception of transactions between Southwest and NPL in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 71, “Accounting for the Effects of Certain Types of Regulation.”
Net Utility Plant. Net utility plant includes gas plant at original cost, less the accumulated provision for depreciation and amortization, plus the unamortized balance of acquisition adjustments. Original cost includes contracted services, material, payroll and related costs such as taxes and benefits, general and administrative expenses, and an allowance for funds used during construction less contributions in aid of construction.
Deferred Purchased Gas Costs. The various regulatory commissions have established procedures to enable Southwest to adjust its billing rates for changes in the cost of gas purchased. The difference between the current cost of gas purchased and the cost of gas recovered in billed rates is deferred. Generally, these deferred amounts are recovered or refunded within one year.
Income Taxes. The Company uses the asset and liability method of accounting for income taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the period that includes the enactment date.
For regulatory and financial reporting purposes, investment tax credits (“ITC”) related to gas utility operations are deferred and amortized over the life of related fixed assets.
southwest gas 2003 annual report
PAGE 43
notes to consolidated financial statements
Gas Operating Revenues. Revenues are recorded when customers are billed. Customer billings are based on monthly meter reads and are calculated in accordance with applicable tariffs. Southwest also recognizes accrued utility revenues for the estimated amount of services rendered between the meter-reading dates in a particular month and the end of such month.
Construction Revenues. The majority of the NPL contracts are performed under unit price contracts. These contracts state prices per unit of installation. Revenues are recorded as installations are completed. Fixed-price contracts use the percentage-of-completion method of accounting and, therefore, take into account the cost, estimated earnings, and revenue to date on contracts not yet completed. The amount of revenue recognized is based on costs expended to date relative to anticipated final contract costs. Revisions in estimates of costs and earnings during the course of the work are reflected in the accounting period in which the facts requiring revision become known. If a loss on a contract becomes known or is anticipated, the entire amount of the estimated ultimate loss is recognized at that time in the financial statements.
Asset Retirement Obligations. In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” which was effective for fiscal years beginning after June 15, 2002. SFAS No. 143 establishes accounting standards for recognition and measurement of liabilities for asset retirement obligations and the associated asset retirement costs. The Company adopted the provisions of SFAS No. 143 as of January 1, 2003.
In accordance with approved regulatory practices, the depreciation expense for Southwest includes a component to recover removal costs associated with utility plant retirements. In accordance with the SEC’s position on presentation of these amounts, management has reclassified $68 million and $55 million, as of December 31, 2003 and 2002, respectively, of estimated removal costs from accumulated depreciation to accumulated removal costs (in the liabilities section of the balance sheet).
Depreciation and Amortization. Utility plant depreciation is computed on the straight-line remaining life method at composite rates considered sufficient to amortize costs over estimated service lives, including components which compensate for salvage value, removal costs and retirements, as approved by the appropriate regulatory agency. When plant is retired from service, the original cost of plant, including cost of removal, less salvage, is charged to the accumulated provision for depreciation. Acquisition adjustments are amortized, as ordered by regulators, over periods which approximate the remaining estimated life of the acquired properties. Costs related to refunding utility debt and debt issuance expenses are deferred and amortized over the weighted-average lives of the new issues. Other regulatory assets, when appropriate, are amortized over time periods authorized by regulators. Nonutility property and equipment are depreciated on a straight-line method based on the estimated useful lives of the related assets. Goodwill amortization for the year 2001 was $400,000. Pursuant to SFAS No. 142, “Goodwill and Other Intangible Assets,” goodwill amortization was eliminated as of January 2002.
Allowance for Funds Used During Construction (“AFUDC”). AFUDC represents the cost of both debt and equity funds used to finance utility construction. AFUDC is capitalized as part of the cost of utility plant. The Company capitalized $2.6 million in 2003, $3.1 million in 2002, and $2.5 million in 2001 of AFUDC related to natural gas utility operations. The debt portion of AFUDC is reported in the consolidated statements of income as an offset to net interest deductions and the equity portion is reported as other income. Utility plant construction costs, including AFUDC, are recovered in authorized rates through depreciation when completed projects are placed into operation, and general rate relief is requested and granted.
southwest gas 2003 annual report
PAGE 44
notes to consolidated financial statements
Earnings Per Share. Basic earnings per share (“EPS”) are calculated by dividing net income by the weighted-average number of shares outstanding during the period. Diluted EPS includes the effect of additional weighted-average common stock equivalents (stock options and performance shares). Unless otherwise noted, the term “Earnings Per Share” refers to Basic EPS. A reconciliation of the shares used in the Basic and Diluted EPS calculations is shown in the following table. Net income was the same for Basic and Diluted EPS calculations.
(in thousands) | ||||||
2003 | 2002 | 2001 | ||||
Average basic shares | 33,760 | 32,953 | 32,122 | |||
EFFECT OF DILUTIVE SECURITIES: | ||||||
Stock options | 73 | 94 | 122 | |||
Performance shares | 208 | 186 | 154 | |||
Average diluted shares | 34,041 | 33,233 | 32,398 | |||
Cash and Cash Equivalents. For purposes of reporting consolidated cash flows, cash and cash equivalents include cash on hand and financial instruments with a maturity of three months or less, but exclude funds held in trust from the issuance of industrial development revenue bonds (“IDRB”).
Reclassifications. Certain reclassifications have been made to the prior year’s financial information to present it on a basis comparable with the current year’s presentation.
Recently Issued Accounting Pronouncements. In January 2003, the FASB issued Interpretation No. 46 “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51” (“FIN 46”) effective July 2003. See Note 5 – Preferred Securities for additional information.
In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” which was effective for contracts entered into or modified after September 30, 2003 with exceptions for certain types of securities. SFAS No. 149 clarifies the definition and characteristics of a derivative and amends other existing pronouncements for consistency. Southwest has fixed-price gas purchase contracts, which are considered normal purchases occurring in the ordinary course of business. The Company does not currently utilize stand-alone derivative instruments for speculative purposes and does not have foreign currency exposure. None of the Company’s long term financial instruments or other contracts are derivatives that are marked to market, or contain embedded derivatives with significant mark-to-market value. The adoption of the standard did not have a material impact on the financial position or results of operations of the Company.
In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” which is effective for all financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. SFAS No. 150 addresses the accounting for certain financial instruments with characteristics of both liabilities and equity that, under previous guidance, issuers could account for as equity. SFAS No. 150 requires those instruments be classified as liabilities in statements of financial position. The adoption of the standard did not have a material impact on the financial position or results of operations of the Company.
southwest gas 2003 annual report
PAGE 45
notes to consolidated financial statements
Stock-Based Compensation. At December 31, 2003, the Company had two stock-based compensation plans, which are described more fully in Note 9 – Employee Benefits. These plans are accounted for in accordance with Accounting Principles Board (“APB”) Opinion No. 25 “Accounting for Stock Issued to Employees” and related interpretations. The following table illustrates the effect on net income and earnings per share if the Company had applied the fair value recognition provision of SFAS No. 123 “Accounting for Stock-Based Compensation” to its stock-based employee compensation:
(thousands of dollars, except per share amounts) | ||||||||||||
2003 | 2002 | 2001 | ||||||||||
Net income, as reported | $ | 38,502 | $ | 43,965 | $ | 37,156 | ||||||
Add: Stock-based employee compensation expense | 2,438 | 1,783 | 1,879 | |||||||||
Deduct: Total stock-based employee compensation | (2,920 | ) | (2,024 | ) | (2,222 | ) | ||||||
Pro forma net income | $ | 38,020 | $ | 43,724 | $ | 36,813 | ||||||
EARNINGS PER SHARE: | ||||||||||||
Basic – as reported | $ | 1.14 | $ | 1.33 | $ | 1.16 | ||||||
Basic – pro forma | 1.13 | 1.33 | 1.15 | |||||||||
Diluted – as reported | 1.13 | 1.32 | 1.15 | |||||||||
Diluted – pro forma | 1.12 | 1.32 | 1.14 |
NOTE 2
utility plant
Net utility plant as of December 31, 2003 and 2002 was as follows:
(thousands of dollars) | ||||||||
DECEMBER 31, | 2003 | 2002 | ||||||
GAS PLANT: | ||||||||
Storage | $ | 4,158 | $ | 4,213 | ||||
Transmission | 215,907 | 196,997 | ||||||
Distribution | 2,496,708 | 2,293,655 | ||||||
General | 197,693 | 198,093 | ||||||
Other | 121,503 | 87,002 | ||||||
3,035,969 | 2,779,960 | |||||||
Less: accumulated depreciation | (896,309 | ) | (814,908 | ) | ||||
Acquisition adjustments, net | 2,533 | 2,714 | ||||||
Construction work in progress | 33,543 | 66,693 | ||||||
Net utility plant | $ | 2,175,736 | $ | 2,034,459 | ||||
Depreciation and amortization expense on gas plant was $118 million in 2003, $113 million in 2002, and $102 million in 2001.
southwest gas 2003 annual report
PAGE 46
notes to consolidated financial statements
Leases and Rentals. Southwest leases the liquefied natural gas (“LNG”) facilities on its northern Nevada system, a portion of its corporate headquarters office complex in Las Vegas, and its administrative offices in Phoenix. The leases provide for current terms which expire in 2005, 2017, and 2009, respectively, with optional renewal terms available at the expiration dates. The rental payments for the LNG facilities are $3.3 million for 2004 and $1.7 million in 2005, when the lease expires in June. The rental payments for the corporate headquarters office complex are $2 million in each of the years 2004 through 2008 and $18.3 million cumulatively thereafter. The rental payments for the Phoenix administrative offices are $1.4 million in 2004, $1.5 million for each of the years 2005 through 2008, and $1 million in 2009 when the lease expires. In addition to the above, the Company leases certain office and construction equipment. The majority of these leases are short-term. These leases are accounted for as operating leases, and for the gas segment are treated as such for regulatory purposes. Rentals included in operating expenses for all operating leases were $20 million in 2003, $26.5 million in 2002, and $28 million in 2001. These amounts include NPL lease expenses of approximately $9.6 million in 2003, $12.3 million in 2002, and $12.6 million in 2001 for various short-term leases of equipment and temporary office sites.
The following is a schedule of future minimum lease payments for noncancellable operating leases (with initial or remaining terms in excess of one year) as of December 31, 2003:
(thousands of dollars) | |||
YEAR ENDING DECEMBER 31, | |||
2004 | $ | 8,408 | |
2005 | 5,991 | ||
2006 | 4,130 | ||
2007 | 3,967 | ||
2008 | 3,997 | ||
Thereafter | 20,543 | ||
Total minimum lease payments | $ | 47,036 | |
southwest gas 2003 annual report
PAGE 47
notes to consolidated financial statements
NOTE 3
receivables and related allowances
Business activity with respect to gas utility operations is conducted with customers located within the three-state region of Arizona, Nevada, and California. At December 31, 2003, the gas utility customer accounts receivable balance was $102 million. Approximately 56 percent of the gas utility customers were in Arizona, 35 percent in Nevada, and 9 percent in California. Although the Company seeks to minimize its credit risk related to utility operations by requiring security deposits from new customers, imposing late fees, and actively pursuing collection on overdue accounts, some accounts are ultimately not collected. Provisions for uncollectible accounts are recorded monthly, as needed, and are included in the ratemaking process as a cost of service. Activity in the allowance for uncollectibles is summarized as follows:
(thousands of dollars) | ||||
ALLOWANCE FOR UNCOLLECTIBLES | ||||
Balance, December 31, 2000 | $ | 1,564 | ||
Additions charged to expense | 3,874 | |||
Accounts written off, less recoveries | (3,567 | ) | ||
Balance, December 31, 2001 | 1,871 | |||
Additions charged to expense | 3,824 | |||
Accounts written off, less recoveries | (3,870 | ) | ||
Balance, December 31, 2002 | 1,825 | |||
Additions charged to expense | 2,523 | |||
Accounts written off, less recoveries | (2,102 | ) | ||
Balance, December 31, 2003 | $ | 2,246 | ||
NOTE 4
regulatory assets and liabilities
Natural gas operations are subject to the regulation of the Arizona Corporation Commission (“ACC”), the Public Utilities Commission of Nevada (“PUCN”), the California Public Utilities Commission (“CPUC”), and the Federal Energy Regulatory Commission (“FERC”). Company accounting policies conform to generally accepted accounting principles applicable to rate-regulated enterprises, principally SFAS No. 71, and reflect the effects of the ratemaking process. SFAS No. 71 allows for the deferral as regulatory assets, costs that otherwise would be expensed if it is probable future recovery from customers will occur. If rate recovery is no longer probable, due to competition or the actions of regulators, Southwest is required to write off the related regulatory asset.
southwest gas 2003 annual report
PAGE 48
notes to consolidated financial statements
The following table represents existing regulatory assets and liabilities:
(thousands of dollars) | ||||||||
DECEMBER 31, | 2003 | 2002 | ||||||
REGULATORY ASSETS: | ||||||||
Deferred purchased gas costs | $ | 9,151 | $ | — | ||||
Accrued purchased gas costs * | 8,800 | — | ||||||
SFAS No. 109 – income taxes, net | 3,700 | 5,035 | ||||||
Unamortized premium on reacquired debt | 18,560 | 12,614 | ||||||
Other | 28,095 | 27,873 | ||||||
68,306 | 45,522 | |||||||
REGULATORY LIABILITIES: | ||||||||
Deferred purchased gas costs | — | (26,718 | ) | |||||
Accumulated removal costs | (68,000 | ) | (55,000 | ) | ||||
Other | (425 | ) | (422 | ) | ||||
Net regulatory assets (liabilities) | $ | (119 | ) | $ | (36,618 | ) | ||
* Included in Prepaids and other current assets on the Consolidated Balance Sheet.
Other regulatory assets include deferred costs associated with rate cases, regulatory studies, and state mandated public purpose programs (including low income and conservation programs), as well as amounts associated with accrued absence time and accrued post-retirement benefits other than pensions.
NOTE 5
preferred securities
In October 1995, Southwest Gas Capital I (the “Trust”), a consolidated wholly owned subsidiary of the Company, issued $60 million of 9.125% Trust Originated Preferred Securities (the “Preferred Securities”). In connection with the Trust issuance of the Preferred Securities and the related purchase by the Company of all of the trust common securities, the Company issued to the Trust $61.8 million principal amount of its 9.125% Subordinated Deferrable Interest Notes, due 2025.
In June 2003, the Company created Southwest Gas Capital II (“Trust II”), a wholly owned subsidiary, as a financing trust for the sole purpose of issuing preferred trust securities for the benefit of the Company. In August 2003, Trust II publicly issued $100 million of 7.70% Preferred Trust Securities (“Preferred Trust Securities”). In connection with the Trust II issuance of the Preferred Trust Securities and the related purchase by the Company for $3.1 million of all of the Trust II common securities (“Common Securities”), the Company issued $103.1 million principal amount of its 7.70% Junior Subordinated Debentures, due 2043 (“Subordinated Debentures”) to Trust II. The sole assets of Trust II are and will be the Subordinated Debentures. The interest and other payment dates on the Subordinated Debentures correspond to the distribution and other payment dates on the Preferred Trust Securities and Common Securities. Under certain circumstances, the Subordinated Debentures may be distributed to the holders of the Preferred Trust Securities and holders of the Common Securities in liquidation of Trust II. The Subordinated Debentures are redeemable at the option of the Company after August 2008 at a redemption price of $25 per Subordinated Debenture plus accrued and unpaid interest. In the event that the Subordinated Debentures are repaid, the Preferred Trust Securities and the Common Securities will be redeemed on a pro rata basis at $25 (par value) per Preferred Trust Security and Common Security plus accumulated and unpaid distributions. Company obligations under the Subordinated Debentures, the Trust Agreement (the agreement under which
southwest gas 2003 annual report
PAGE 49
notes to consolidated financial statements
Trust II was formed), the guarantee of payment of certain distributions, redemption payments and liquidation payments with respect to the Preferred Trust Securities to the extent Trust II has funds available therefore and the indenture governing the Subordinated Debentures, including the Company agreement pursuant to such indenture to pay all fees and expenses of Trust II, other than with respect to the Preferred Trust Securities and Common Securities, taken together, constitute a full and unconditional guarantee on a subordinated basis by the Company of payments due on the Preferred Trust Securities. As of December 31, 2003, 4.1 million Preferred Trust Securities were outstanding.
The Company has the right to defer payments of interest on the Subordinated Debentures by extending the interest payment period at any time for up to 20 consecutive quarters (each, an “Extension Period”). If interest payments are so deferred, distributions to Preferred Trust Securities holders will also be deferred. During such Extension Period, distributions will continue to accrue with interest thereon (to the extent permitted by applicable law) at an annual rate of 7.70% per annum compounded quarterly. There could be multiple Extension Periods of varying lengths throughout the term of the Subordinated Debentures. If the Company exercises the right to extend an interest payment period, the Company shall not during such Extension Period (i) declare or pay dividends on, or make a distribution with respect to, or redeem, purchase or acquire or make a liquidation payment with respect to, any of its capital stock, or (ii) make any payment of interest, principal, or premium, if any, on or repay, repurchase, or redeem any debt securities issued by the Company that rank equal with or junior to the Subordinated Debentures; provided, however, that restriction (i) above does not apply to any stock dividends paid by the Company where the dividend stock is the same as that on which the dividend is being paid. The Company has no present intention of exercising its right to extend the interest payment period on the Subordinated Debentures.
A portion of the net proceeds from the issuance of the Preferred Trust Securities was used to complete the redemption of the 9.125% Trust Originated Preferred Securities effective September 2003 at a redemption price of $25 per Preferred Security, totaling $60 million plus accrued interest of $1.3 million.
In January 2003, the FASB issued Interpretation No. 46 “Consolidation of Variable Interest Entities – an Interpretation of ARB No. 51” (“FIN 46”) effective July 2003. This Interpretation of Accounting Research Bulletin No. 51 “Consolidated Financial Statements,” addresses consolidation by business enterprises of variable interest entities. FIN 46 explains how to identify variable interest entities and how an enterprise assesses its interests in a variable interest entity to decide whether to consolidate that entity. Trust II, the issuer of the preferred trust securities, meets the definition of a variable interest entity.
Although the Company owns 100 percent of the common voting securities of Trust II, under current interpretation of FIN 46, the Company is not considered the primary beneficiary of this trust and therefore Trust II is not consolidated. The adoption of FIN 46 results in the Company reflecting a liability to Trust II (which under the prior accounting treatment would have been eliminated in consolidation) instead of to the holders of the preferred trust securities. As a result, payments and amortizations associated with the liability are classified on the consolidated statements of income as Net interest deductions on subordinated debentures. The $103.1 million Subordinated Debentures are shown on the balance sheet of the Company net of the $3.1 million Common Securities as Subordinated debentures due to Southwest Gas Capital II.
southwest gas 2003 annual report
PAGE 50
notes to consolidated financial statements
NOTE 6
long-term debt
(thousands of dollars) | ||||||||||||||
2003 | 2002 | |||||||||||||
DECEMBER 31, | CARRYING AMOUNT | MARKET VALUE | CARRYING AMOUNT | MARKET VALUE | ||||||||||
DEBENTURES: | ||||||||||||||
7½% Series, due 2006 | $ | 75,000 | $ | 83,149 | $ | 75,000 | $ | 81,889 | ||||||
Notes, 8.375%, due 2011 | 200,000 | 241,155 | 200,000 | 226,128 | ||||||||||
Notes, 7.625%, due 2012 | 200,000 | 232,198 | 200,000 | 218,166 | ||||||||||
8% Series, due 2026 | 75,000 | 88,240 | 75,000 | 79,017 | ||||||||||
Medium-term notes, 7.75% series, due 2005 | 25,000 | 27,198 | 25,000 | 27,342 | ||||||||||
Medium-term notes, 6.89% series, due 2007 | 17,500 | 19,443 | 17,500 | 18,781 | ||||||||||
Medium-term notes, 6.27% series, due 2008 | 25,000 | 27,219 | 25,000 | 25,946 | ||||||||||
Medium-term notes, 7.59% series, due 2017 | 25,000 | 29,217 | 25,000 | 26,711 | ||||||||||
Medium-term notes, 7.78% series, due 2022 | 25,000 | 29,076 | 25,000 | 25,725 | ||||||||||
Medium-term notes, 7.92% series, due 2027 | 25,000 | 29,220 | 25,000 | 26,134 | ||||||||||
Medium-term notes, 6.76% series, due 2027 | 7,500 | 7,725 | 7,500 | 6,870 | ||||||||||
Unamortized discount | (5,957 | ) | — | (6,534 | ) | — | ||||||||
694,043 | 693,466 | |||||||||||||
Revolving credit facility and commercial paper | 100,000 | 100,000 | 100,000 | 100,000 | ||||||||||
INDUSTRIAL DEVELOPMENT REVENUE BONDS: | ||||||||||||||
VARIABLE-RATE BONDS: | ||||||||||||||
Tax-exempt Series A, due 2028 | 50,000 | 50,000 | 50,000 | 50,000 | ||||||||||
2003 Series A, due 2038 | 50,000 | 50,000 | — | — | ||||||||||
2003 Series B, due 2038 | 50,000 | 50,000 | — | — | ||||||||||
FIXED-RATE BONDS: | ||||||||||||||
7.30% 1992 Series A, due 2027 | — | — | 30,000 | 30,600 | ||||||||||
7.50% 1992 Series B, due 2032 | — | — | 100,000 | 102,000 | ||||||||||
6.50% 1993 Series A, due 2033 | 75,000 | 76,500 | 75,000 | 75,000 | ||||||||||
6.10% 1999 Series A, due 2038 | 12,410 | 12,596 | 12,410 | 13,744 | ||||||||||
5.95% 1999 Series C, due 2038 | 14,320 | 15,811 | 14,320 | 15,322 | ||||||||||
5.55% 1999 Series D, due 2038 | 8,270 | 9,014 | 8,270 | 8,332 | ||||||||||
5.45% 2003 Series C, due 2038 | 30,000 | 32,826 | — | — | ||||||||||
3.35% 2003 Series D, due 2038 | 20,000 | 20,000 | — | — | ||||||||||
5.80% 2003 Series E, due 2038 | 15,000 | 16,809 | — | — | ||||||||||
Unamortized discount | (1,986 | ) | — | (3,169 | ) | — | ||||||||
323,014 | 286,831 | |||||||||||||
Other | 10,542 | — | 20,556 | — | ||||||||||
1,127,599 | 1,100,853 | |||||||||||||
Less: current maturities | (6,435 | ) | (8,705 | ) | ||||||||||
Long-term debt, less current maturities | $ | 1,121,164 | $ | 1,092,148 | ||||||||||
southwest gas 2003 annual report
PAGE 51
notes to consolidated financial statements
In May 2002, the Company replaced a $350 million revolving credit facility that was to expire in June 2002 with a $125 million three-year facility and a $125 million 364-day facility. Interest rates for the new facility are calculated at either the London Interbank Offering Rate (“LIBOR”) plus or minus a competitive margin, or the greater of the prime rate or one half of one percent plus the Federal Funds rate. The Company has designated $100 million of the total facility as long-term debt and uses the remaining $150 million for working capital purposes and has designated the related outstanding amounts as short-term debt.
In October 2002, the Company entered into a $50 million commercial paper program. Any issuance under the commercial paper program is supported by the Company’s current revolving credit facility and, therefore, does not represent new borrowing capacity. Interest rates for the new program are calculated at the then current commercial paper rate. At December 31, 2003, $50 million was outstanding on the commercial paper program.
In March 2003, the Company issued several series of Clark County, Nevada Industrial Development Revenue Bonds (“IDRBs”) totaling $165 million, due 2038. Of this total, variable-rate IDRBs ($50 million 2003 Series A and $50 million 2003 Series B) were used to refinance the $100 million 7.50% 1992 Series B, fixed-rate IDRBs due 2032. At December 31, 2003, the effective interest rate including all fees on the new Series A and Series B IDRBs was 2.66%. The $30 million 7.30% 1992 Series A, fixed-rate IDRBs due 2027 was refinanced with a $30 million 5.45% 2003 Series C fixed-rate IDRBs. An incremental $35 million ($20 million 3.35% 2003 Series D and $15 million 5.80% Series E fixed-rate IDRBs) was used to finance construction expenditures in southern Nevada during the first and second quarters of 2003. The Series C and Series E were set with an initial interest rate period of 10 years, while the Series D has an initial interest rate period of 18 months. After the initial interest rate periods, the Series C, D, and E interest rates will be reset at then prevailing market rates for periods not to exceed the maturity date of March 1, 2038.
The 2003 Series A and Series B IDRBs are supported by two letters of credit totaling $101.7 million, which expire in March 2006. These IDRBs are set at weekly rates and the letters of credit support the payment of principal or a portion of the purchase price corresponding to the principal of the IDRBs (while in the weekly rate mode).
The Company’s Revolving Credit Facilities contain financial covenants including a maximum leverage ratio of 70 percent (debt to capitalization as defined) and a minimum net worth calculation of $450 million (adjusted for sales of securities after May 31, 2002). In October 2003, a $55.3 million letter of credit, which supports the City of Big Bear $50 million tax-exempt Series A IDRBs, due 2028, was renewed for a three-year period expiring in October 2006. This letter of credit has a maximum leverage ratio of 70 percent (debt to capitalization as defined) and a minimum net worth calculation of $450 million (adjusted for sales of equity securities after July 1, 2003). If the Company were not in compliance with these covenants, an event of default would occur, which if not cured could cause the amounts outstanding to become due and payable. This would also trigger cross-default provisions in substantially all other outstanding indebtedness of the Company. At December 31, 2003, the Company was in compliance with the applicable covenants.
The interest rate on the tax-exempt variable-rate IDRBs averaged 2.73 percent in 2003 and 2.82 percent in 2002. The rates for the variable-rate IDRBs are established on a weekly basis. The Company has the option to convert from the current weekly rates to daily rates, term rates, or variable-term rates.
The fair value of the revolving credit facility approximates carrying value. Market values for the debentures and fixed-rate IDRBs were determined based on dealer quotes using trading records for December 31, 2003 and 2002, as applicable, and other secondary sources which are customarily consulted for data of this kind. The carrying values of variable-rate IDRBs were used as estimates of fair value based upon the variable interest rates of the bonds.
southwest gas 2003 annual report
PAGE 52
notes to consolidated financial statements
Estimated maturities of long-term debt for the next five years are $6.4 million, $128.1 million, $76 million, $17.5 million, and $25 million, respectively.
The $7.5 million medium-term notes, 6.76% series, due 2027 contains a put feature at the discretion of the bondholder on one date only in 2007. If the bondholder does not exercise the put on that date, the notes will reach maturity in 2027. If the bondholder exercises the put, the maturities of long-term debt for 2007 will total $25 million.
NOTE 7
short-term debt
As discussed in Note 6, Southwest has a $250 million credit facility consisting of a $125 million three-year facility and a $125 million 364-day facility. Effective May 2003, the Company renewed the $125 million 364-day facility for an additional year with no significant changes in rates or terms. Short-term borrowings were $52 million and $53 million at December 31, 2003 and 2002, respectively. The weighted-average interest rates on these borrowings were 2.04 percent at December 31, 2003 and 2.35 percent at December 31, 2002.
NOTE 8
commitments and contingencies
California General Rate Cases. In February 2002, Southwest filed general rate applications with the California Public Utilities Commission (“CPUC”) for its northern and southern California jurisdictions. The applications sought annual increases over a five-year rate case cycle with a cumulative total of $6.3 million in northern California and $17.2 million in southern California. The last general rate increases received in California were January 1998 in northern California and January 1995 in southern California.
In July 2002, the Office of Ratepayer Advocates (“ORA”) filed testimony in the rate case recommending significant reductions to the rate increases sought by Southwest. The ORA concurred with the majority of the Southwest rate design proposals including a margin tracking mechanism to mitigate weather-related and other usage variations. At the hearing that was held in August 2002, Southwest modified its proposal from a five-year to a three-year rate case cycle and accordingly reduced its cumulative request to $4.8 million in northern California and $10.7 million in southern California. For 2003, the amounts requested were $2.6 million in northern California and $5.7 million in southern California. The final general rate case decision, originally anticipated to have an effective date of January 2003, was delayed due to the reassignment of the Administrative Law Judge (“ALJ”) assigned to the case. As a result of this delay, Southwest filed a motion during the first quarter of 2003 requesting authorization to establish a memorandum account to track the related revenue shortfall between the existing and proposed rates in the general rate case filing. This motion was approved, effective May 2003. In October 2003, the ALJ rendered a draft decision (“proposed decision” or “PD”) on the general rate case. The PD was modified in February 2004. If approved as modified, the PD would increase rates by about 60 percent of the 2003 amount filed for and provide for attrition increases beginning in 2004. Southwest filed comments largely in support of the PD. In January 2004, an alternate decision (“AD”) from one of the commissioners was received, reducing the rate increase in southern California as proposed in the PD by $2 million, with no significant change to northern California. In addition, the AD proposed a disallowance of $12.2 million in gas costs. Southwest filed comments vehemently opposed to the AD. The general rate case is on the agenda for mid-March; however, management can not determine which, if any, of the proposed or alternate decisions will be approved.
Legal and Regulatory Proceedings. The Company is a defendant in miscellaneous legal proceedings. The Company is also a party to various regulatory proceedings. The ultimate dispositions of these proceedings are not presently determinable; however, it is the opinion of management that no litigation or regulatory proceeding to which the Company is subject will have a material adverse impact on its financial position or results of operations.
southwest gas 2003 annual report
PAGE 53
notes to consolidated financial statements
NOTE 9
employee benefits
Southwest has a noncontributory qualified retirement plan with defined benefits covering substantially all employees. Southwest also provides postretirement benefits other than pensions (“PBOP”) to its qualified retirees for health care, dental, and life insurance benefits.
In December 2003, the FASB issued SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits” expanding financial statement disclosure requirements for defined benefit plans. The following disclosures reflect the new requirements. In addition to expanded annual disclosures, various elements of pension and other postretirement benefit costs are required to be reported on a quarterly basis.
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“Medicare Act”) was signed into law. The Medicare Act includes a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans which have a benefit at least actuarially equivalent to that included in the Medicare Act. The Company makes fixed contributions for health care benefits of employees who retire after 1988, but pays up to 100 percent of covered health care costs for employees who retired prior to 1989. A prescription drug benefit is provided for the approximately 100 pre-1989 retirees. The Company is electing to defer recognizing the effects of the Medicare Act until authoritative guidance on the accounting for the federal subsidy is issued. The following disclosures of APBO and net periodic benefit cost do not reflect the effects of the Medicare Act. When authoritative guidance is issued, previously reported information may change.
Investment objectives and strategies for the retirement plan are developed and approved by the Pension Plan Investment Committee of the Board of Directors of the Company. They are designed to preserve capital, maintain minimum liquidity required for retirement plan operations and effectively manage pension assets.
A target portfolio of investments in the retirement plan is developed by the Pension Plan Investment Committee and is reevaluated periodically. Rate of return assumptions are determined by evaluating performance expectations of the target portfolio. Projected benefit obligations are estimated using actuarial assumptions and Company benefit policy. A target mix of assets is then determined based on acceptable risk versus estimated returns in order to fund the benefit obligation. The current percentage ranges of the target portfolio are:
Type of Investment | Percentage Range | |
Equity securities | 55 to 67 | |
Debt securities | 32 to 38 | |
Other | 1 to 7 |
The Company’s pension and related benefits plans utilize various assumptions which impact the expense and funding levels of these plans. The Company is lowering the expected rate of return on plan assets assumption for these plans from 8.95% to 8.75% for 2004. The lower rate of return reflects anticipated investment returns on a long-term basis considering asset mix, projected and historical investment returns. This change, coupled with a 25 basis point reduction in the discount rate, will result in a $2.3 million increase in pension expense for 2004.
southwest gas 2003 annual report
PAGE 54
notes to consolidated financial statements
The following tables set forth the retirement plan and PBOP funded status and amounts recognized on the Consolidated Balance Sheets and Statements of Income.
(thousands of dollars) | ||||||||||||||||
QUALIFIED RETIREMENT PLAN | PBOP | |||||||||||||||
2003 | 2002 | 2003 | 2002 | |||||||||||||
CHANGE IN BENEFIT OBLIGATIONS | ||||||||||||||||
Benefit obligation for service rendered to | $ | 319,404 | $ | 288,046 | $ | 31,307 | $ | 28,204 | ||||||||
Service cost | 12,267 | 11,585 | 675 | 595 | ||||||||||||
Interest cost | 21,243 | 20,568 | 2,095 | 1,992 | ||||||||||||
Actuarial loss (gain) | 25,580 | 7,905 | 1,850 | 1,966 | ||||||||||||
Benefits paid | (9,400 | ) | (8,700 | ) | (1,560 | ) | (1,450 | ) | ||||||||
Benefit obligation at end of year (PBO/APBO) | $ | 369,094 | $ | 319,404 | $ | 34,367 | $ | 31,307 | ||||||||
CHANGE IN PLAN ASSETS | ||||||||||||||||
Market value of plan assets at beginning of year | $ | 242,159 | $ | 274,103 | $ | 12,912 | $ | 12,402 | ||||||||
Actual return on plan assets | 49,464 | (28,344 | ) | 1,477 | (647 | ) | ||||||||||
Employer contributions | 11,213 | 5,100 | 1,465 | 1,157 | ||||||||||||
Benefits paid | (9,400 | ) | (8,700 | ) | — | — | ||||||||||
Market value of plan assets at end of year | $ | 293,436 | $ | 242,159 | $ | 15,854 | $ | 12,912 | ||||||||
Funded status | $ | (75,658 | ) | $ | (77,245 | ) | $ | (18,513 | ) | $ | (18,395 | ) | ||||
Unrecognized net actuarial loss (gain) | 56,649 | 52,936 | 6,741 | 6,760 | ||||||||||||
Unrecognized transition obligation (2004/2012) | — | 795 | 7,802 | 8,669 | ||||||||||||
Unrecognized prior service cost | 9 | 66 | — | — | ||||||||||||
Prepaid (accrued) benefit cost | $ | (19,000 | ) | $ | (23,448 | ) | $ | (3,970 | ) | $ | (2,966 | ) | ||||
WEIGHTED-AVERAGE ASSUMPTIONS (BENEFIT OBLIGATION) | ||||||||||||||||
Discount rate | 6.50 | % | 6.75 | % | 6.50 | % | 6.75 | % | ||||||||
Rate of compensation increase | 4.25 | % | 4.25 | % | 4.25 | % | 4.25 | % | ||||||||
ASSET ALLOCATION | ||||||||||||||||
Equity securities | 64 | % | 55 | % | 35 | % | 28 | % | ||||||||
Debt securities | 30 | % | 39 | % | 16 | % | 20 | % | ||||||||
Other | 6 | % | 6 | % | 49 | % | 52 | % | ||||||||
Total | 100 | % | 100 | % | 100 | % | 100 | % | ||||||||
southwest gas 2003 annual report
PAGE 55
notes to consolidated financial statements
The measurement date used to determine pension and other postretirement benefit measurements was December 31, 2003. Estimated funding for the plans above during 2004 is approximately $14 million. The accumulated benefit obligation for the retirement plan was $289 million and $249 million at December 31, 2003 and 2002, respectively.
For PBOP measurement purposes, the per capita cost of covered health care benefits is assumed to increase five percent annually. The Company makes fixed contributions for health care benefits of employees who retire after 1988, but pays up to 100 percent of covered health care costs for employees who retired prior to 1989. The assumed annual rate of increase noted above applies to the benefit obligations of pre-1989 retirees only.
components of net periodic benefit cost:
(thousands of dollars) | ||||||||||||||||||||||||
QUALIFIED RETIREMENT PLAN | PBOP | |||||||||||||||||||||||
2003 | 2002 | 2001 | 2003 | 2002 | 2001 | |||||||||||||||||||
Service cost | $ | 12,267 | $ | 11,585 | $ | 11,057 | $ | 675 | $ | 595 | $ | 591 | ||||||||||||
Interest cost | 21,243 | 20,568 | 18,805 | 2,095 | 1,992 | 1,856 | ||||||||||||||||||
Expected return on plan assets | (27,217 | ) | (27,178 | ) | (25,383 | ) | (1,205 | ) | (1,184 | ) | (1,073 | ) | ||||||||||||
Amortization of prior service costs | 57 | 57 | 57 | — | — | — | ||||||||||||||||||
Amortization of unrecognized | ||||||||||||||||||||||||
transition obligation | 795 | 837 | 837 | 867 | 867 | 867 | ||||||||||||||||||
Amortization of net (gain) loss | — | (207 | ) | (568 | ) | 257 | — | — | ||||||||||||||||
Net periodic benefit cost | $ | 7,145 | $ | 5,662 | $ | 4,805 | $ | 2,689 | $ | 2,270 | $ | 2,241 | ||||||||||||
WEIGHTED-AVERAGE ASSUMPTIONS (NET BENEFIT COST) | ||||||||||||||||||||||||
Discount rate | 6.75 | % | 7.25 | % | 7.25 | % | 6.75 | % | 7.25 | % | 7.25 | % | ||||||||||||
Expected return on plan assets | 8.95 | % | 9.25 | % | 9.25 | % | 8.95 | % | 9.25 | % | 9.25 | % | ||||||||||||
Rate of compensation increase | 4.25 | % | 4.75 | % | 4.75 | % | 4.25 | % | 4.75 | % | 4.75 | % |
In addition to the retirement plan, Southwest has a separate unfunded supplemental retirement plan which is limited to officers. The plan is noncontributory with defined benefits. Plan costs were $2.7 million in 2003, $3 million in 2002, and $2.9 million in 2001. The accumulated benefit obligation of the plan was $24 million at December 31, 2003.
The Employees’ Investment Plan provides for purchases of various mutual fund investments and Company common stock by eligible Southwest employees through deductions of a percentage of base compensation, subject to IRS limitations. Southwest matches one-half of amounts deferred. The maximum matching contribution is three percent of an employee’s annual compensation. The cost of the plan was $3.3 million in 2003, $3.1 million in 2002, and $3 million in 2001. NPL has a separate plan, the cost and liability for which are not significant.
Southwest has a deferred compensation plan for all officers and members of the Board of Directors. The plan provides the opportunity to defer up to 100 percent of annual cash compensation. Southwest matches one-half of amounts deferred by officers. The maximum matching contribution is three percent of an officer’s annual salary. Payments of compensation deferred, plus interest, are made in equal monthly installments over 10, 15, or 20 years, as elected by the participant. Directors have an additional option to receive such payments over a five-year period. Deferred compensation earns interest at a rate determined each January. The interest rate equals 150 percent of Moody’s Seasoned Corporate Bond Rate Index.
southwest gas 2003 annual report
PAGE 56
notes to consolidated financial statements
At December 31, 2003, the Company had two stock-based compensation plans. These plans are accounted for in accordance with APB Opinion No. 25 “Accounting for Stock Issued to Employees.” In connection with the stock-based compensation plans, the Company recognized compensation expense of $4.1 million in 2003, $3 million in 2002, and $3.1 million in 2001.
Under one plan, the Company may grant options to purchase shares of common stock to key employees and outside directors. Each option has an exercise price equal to the market price of Company common stock on the date of grant and a maximum term of ten years. The options vest 40 percent at the end of year one and 30 percent at the end of years two and three. The grant date fair value of the options was estimated using the extended binomial option pricing model. The following assumptions were used in the valuation calculation:
2003 | 2002 | 2001 | ||||
Dividend yield | 3.94% | 3.64% | 3.60% | |||
Risk-free interest rate range | 1.06 to 2.17% | 1.70 to 2.63% | 2.17 to 3.82% | |||
Expected volatility range | 16 to 25% | 23 to 31% | 22 to 27% | |||
Expected life | 1 to 3 years | 1 to 3 years | 1 to 3 years |
The following tables summarize Company stock option plan activity and related information:
(thousands of options) | ||||||||||||||||||
2003 | 2002 | 2001 | ||||||||||||||||
NUMBER OF OPTIONS | WEIGHTED- AVERAGE EXERCISE PRICE | NUMBER OF OPTIONS | WEIGHTED- AVERAGE EXERCISE PRICE | NUMBER OF OPTIONS | WEIGHTED- AVERAGE EXERCISE PRICE | |||||||||||||
Outstanding at the beginning of the year | 1,260 | $ | 21.66 | 1,123 | $ | 20.79 | 990 | $ | 18.94 | |||||||||
Granted during the year | 348 | 21.05 | 320 | 21.97 | 317 | 23.23 | ||||||||||||
Exercised during the year | (106 | ) | 17.18 | (183 | ) | 16.95 | (184 | ) | 15.07 | |||||||||
Forfeited during the year | — | — | — | — | — | — | ||||||||||||
Expired during the year | — | — | — | — | — | — | ||||||||||||
Outstanding at year end | 1,502 | $ | 21.83 | 1,260 | $ | 21.66 | 1,123 | $ | 20.79 | |||||||||
Exercisable at year end | 868 | $ | 21.96 | 677 | $ | 21.46 | 597 | $ | 21.00 | |||||||||
The weighted-average grant-date fair value of options granted was $1.90 for 2003, $2.69 for 2002, and $2.81 for 2001. The following table summarizes information about stock options outstanding at December 31, 2003:
(thousands of options) | ||||||||||||
OPTIONS OUTSTANDING | OPTIONS EXERCISABLE | |||||||||||
RANGE OF EXERCISE PRICE | NUMBER OUTSTANDING | WEIGHTED- AVERAGE REMAINING CONTRACTUAL LIFE | WEIGHTED- AVERAGE EXERCISE PRICE | NUMBER EXERCISABLE | WEIGHTED- AVERAGE EXERCISE PRICE | |||||||
$15.00 to $19.13 | 285 | 5.1 Years | $ | 17.64 | 285 | $ | 17.64 | |||||
$20.49 to $24.50 | 1,099 | 8.1 Years | $ | 22.16 | 465 | $ | 22.84 | |||||
$28.75 to $28.94 | 118 | 5.5 Years | $ | 28.91 | 118 | $ | 28.91 |
southwest gas 2003 annual report
PAGE 57
notes to consolidated financial statements
In addition to the option plan, the Company may issue restricted stock in the form of performance shares to encourage key employees to remain in its employment to achieve short-term and long-term performance goals. Plan participants are eligible to receive a cash bonus (i.e., short-term incentive) and performance shares (i.e., long-term incentive). The performance shares vest after three years from issuance and are subject to a final adjustment as determined by the Board of Directors. The following table summarizes the activity of this plan:
(thousands of shares) | ||||||||||||
YEAR ENDED DECEMBER 31, | 2003 | 2002 | 2001 | |||||||||
Nonvested performance shares at beginning of year | 345 | 314 | 237 | |||||||||
Performance shares granted | 147 | 122 | 142 | |||||||||
Performance shares forfeited | — | — | — | |||||||||
Shares vested and issued | (111 | ) | (91 | ) | (65 | ) | ||||||
Nonvested performance shares at end of year | 381 | 345 | 314 | |||||||||
Average grant date fair value of award | $ | 22.21 | $ | 22.35 | $ | 19.91 | ||||||
NOTE 10
income taxes
Income tax expense (benefit) consists of the following:
(thousands of dollars) | ||||||||||||
YEAR ENDED DECEMBER 31, | 2003 | 2002 | 2001 | |||||||||
CURRENT: | ||||||||||||
Federal | $ | (24,176 | ) | $ | 5,546 | $ | 27,750 | |||||
State | (4,421 | ) | 3,462 | 2,078 | ||||||||
(28,597 | ) | 9,008 | 29,828 | |||||||||
DEFERRED: | ||||||||||||
Federal | 41,474 | 14,819 | (9,902 | ) | ||||||||
State | 4,005 | (2,410 | ) | (341 | ) | |||||||
45,479 | 12,409 | (10,243 | ) | |||||||||
Total income tax expense | $ | 16,882 | $ | 21,417 | $ | 19,585 | ||||||
Deferred income tax expense (benefit) consists of the following significant components:
(thousands of dollars) | ||||||||||||
YEAR ENDED DECEMBER 31, | 2003 | 2002 | 2001 | |||||||||
DEFERRED FEDERAL AND STATE: | ||||||||||||
Property-related items | $ | 46,808 | $ | 44,491 | $ | 19,560 | ||||||
Purchased gas cost adjustments | 1,030 | (29,087 | ) | (26,975 | ) | |||||||
Employee benefits | (1,767 | ) | (5,113 | ) | (2,121 | ) | ||||||
All other deferred | 276 | 2,986 | 161 | |||||||||
Total deferred federal and state | 46,347 | 13,277 | (9,375 | ) | ||||||||
Deferred ITC, net | (868 | ) | (868 | ) | (868 | ) | ||||||
Total deferred income tax expense | $ | 45,479 | $ | 12,409 | $ | (10,243 | ) | |||||
southwest gas 2003 annual report
PAGE 58
notes to consolidated financial statements
The consolidated effective income tax rate for the period ended December 31, 2003 and the two prior periods differs from the federal statutory income tax rate. The sources of these differences and the effect of each are summarized as follows:
YEAR ENDED DECEMBER 31, | 2003 | 2002 | 2001 | ||||||
Federal statutory income tax rate | 35.0 | % | 35.0 | % | 35.0 | % | |||
Net state tax liability | 2.4 | 1.0 | 3.2 | ||||||
Property-related items | 1.3 | — | 1.5 | ||||||
Effect of closed tax years and resolved issues | (3.6 | ) | — | (4.4 | ) | ||||
Tax credits | (1.6 | ) | (1.3 | ) | (1.5 | ) | |||
Corporate owned life insurance | (2.3 | ) | — | (0.5 | ) | ||||
All other differences | (0.7 | ) | (1.9 | ) | 1.2 | ||||
Consolidated effective income tax rate | 30.5 | % | 32.8 | % | 34.5 | % | |||
Deferred tax assets and liabilities consist of the following:
(thousands of dollars) | ||||||||
DECEMBER 31, | 2003 | 2002 | ||||||
DEFERRED TAX ASSETS: | ||||||||
Deferred income taxes for future amortization of ITC | $ | 8,037 | $ | 8,574 | ||||
Employee benefits | 27,416 | 25,650 | ||||||
Alternative minimum tax | 36,681 | 23,874 | ||||||
Net operating losses & credits | 24,200 | — | ||||||
Other | 6,076 | 4,195 | ||||||
Valuation allowance | — | — | ||||||
102,410 | 62,293 | |||||||
DEFERRED TAX LIABILITIES: | ||||||||
Property-related items, including accelerated depreciation | 331,770 | 247,954 | ||||||
Regulatory balancing accounts | 5,379 | 4,349 | ||||||
Property-related items previously flowed through | 11,737 | 13,609 | ||||||
Unamortized ITC | 12,933 | 13,801 | ||||||
Debt-related costs | 5,777 | 4,378 | ||||||
Other | 5,232 | 4,476 | ||||||
372,828 | 288,567 | |||||||
Net deferred tax liabilities | $ | 270,418 | $ | 226,274 | ||||
Current | $ | (6,914 | ) | $ | (3,084 | ) | ||
Noncurrent | 277,332 | 229,358 | ||||||
Net deferred tax liabilities | $ | 270,418 | $ | 226,274 | ||||
At December 31, 2003, the Company has a federal net operating loss carryforward of $64.7 million which expires in 2022 to 2023 and a federal general business credit carryforward of $1.4 million which expires in 2011 to 2022. The Company also has an Arizona net operating loss carryforward of $33.1 million which expires in 2005 to 2007 and an Arizona tax credit carryforward of $826,000 which expires in 2004 to 2007.
southwest gas 2003 annual report
PAGE 59
notes to consolidated financial statements
NOTE 11
segment information
Company operating segments are determined based on the nature of their activities. The natural gas operations segment is engaged in the business of purchasing, transporting, and distributing natural gas. Revenues are generated from the sale and transportation of natural gas. The construction services segment is engaged in the business of providing utility companies with trenching and installation, replacement, and maintenance services for energy distribution systems.
The accounting policies of the reported segments are the same as those described within Note 1 – Summary of Significant Accounting Policies. NPL accounts for the services provided to Southwest at contractual (market) prices. At December 31, 2003 and 2002, consolidated accounts receivable included $5.8 million and $6 million, respectively, which were not eliminated during consolidation.
The financial information pertaining to the natural gas operations and construction services segments for each of the three years in the period ended December 31, 2003 is as follows:
(thousands of dollars) | |||||||||||
2003 | GAS OPERATIONS | CONSTRUCTION SERVICES | ADJUSTMENTS | TOTAL | |||||||
Revenues from unaffiliated customers | $ | 1,034,353 | $ | 137,717 | $ | 1,172,070 | |||||
Intersegment sales | — | 58,934 | 58,934 | ||||||||
Total | $ | 1,034,353 | $ | 196,651 | $ | 1,231,004 | |||||
Interest expense | $ | 78,931 | $ | 855 | $ | 79,786 | |||||
Depreciation and amortization | $ | 120,791 | $ | 15,648 | $ | 136,439 | |||||
Income tax expense | $ | 13,920 | $ | 2,962 | $ | 16,882 | |||||
Segment income | $ | 34,211 | $ | 4,291 | $ | 38,502 | |||||
Segment assets | $ | 2,528,332 | $ | 79,774 | $ | 2,608,106 | |||||
Capital expenditures | $ | 228,288 | $ | 12,383 | $ | 240,671 | |||||
2002 | GAS OPERATIONS | CONSTRUCTION SERVICES | ADJUSTMENTS | TOTAL | |||||||
Revenues from unaffiliated customers | $ | 1,115,900 | $ | 134,625 | $ | 1,250,525 | |||||
Intersegment sales | — | 70,384 | 70,384 | ||||||||
Total | $ | 1,115,900 | $ | 205,009 | $ | 1,320,909 | |||||
Interest expense | $ | 78,505 | $ | 1,466 | $ | 79,971 | |||||
Depreciation and amortization | $ | 115,175 | $ | 15,035 | $ | 130,210 | |||||
Income tax expense | $ | 18,493 | $ | 2,924 | $ | 21,417 | |||||
Segment income | $ | 39,228 | $ | 4,737 | $ | 43,965 | |||||
Segment assets | $ | 2,345,407 | $ | 87,521 | $ | 2,432,928 | |||||
Capital expenditures | $ | 263,576 | $ | 19,275 | $ | 282,851 | |||||
southwest gas 2003 annual report
PAGE 60
notes to consolidated financial statements
(thousands of dollars) | |||||||||||||
2001 | GAS OPERATIONS | CONSTRUCTION SERVICES | ADJUSTMENTS | TOTAL | |||||||||
Revenues from unaffiliated customers | $ | 1,193,102 | $ | 135,655 | $ | 1,328,757 | |||||||
Intersegment sales | — | 67,931 | 67,931 | ||||||||||
Total | $ | 1,193,102 | $ | 203,586 | $ | 1,396,688 | |||||||
Interest expense | $ | 78,746 | $ | 1,985 | $ | 80,731 | |||||||
Depreciation and amortization | $ | 104,498 | $ | 13,950 | $ | 118,448 | |||||||
Income tax expense | $ | 16,098 | $ | 3,487 | $ | 19,585 | |||||||
Segment income | $ | 32,626 | $ | 4,530 | $ | 37,156 | |||||||
Segment assets | $ | 2,289,111 | $ | 83,228 | $ | (2,727 | ) | $ | 2,369,612 | ||||
Capital expenditures | $ | 248,352 | $ | 17,228 | $ | 265,580 | |||||||
Construction services segment assets include deferred tax assets of $2.5 million in 2001, which were netted against gas operations segment deferred tax liabilities during consolidation. Construction services segment liabilities include taxes payable of $204,000 in 2001, which were netted against gas operations segment tax receivable during consolidation.
NOTE 12
quarterly financial data (unaudited)
(thousands of dollars, except per share amounts) | ||||||||||||||
QUARTER ENDED | ||||||||||||||
MARCH 31 | JUNE 30 | SEPTEMBER 30 | DECEMBER 31 | |||||||||||
2003 | ||||||||||||||
Operating revenues | $ | 403,285 | $ | 255,852 | $ | 220,162 | $ | 351,705 | ||||||
Operating income (loss) | 62,314 | 11,789 | (8,285 | ) | 69,287 | |||||||||
Net income (loss) | 25,539 | (4,104 | ) | (17,407 | ) | 34,474 | ||||||||
Basic earnings (loss) per common share* | 0.76 | (0.12 | ) | (0.51 | ) | 1.01 | ||||||||
Diluted earnings (loss) per common share* | 0.76 | (0.12 | ) | (0.51 | ) | 1.00 | ||||||||
2002 | ||||||||||||||
Operating revenues | $ | 499,501 | $ | 261,123 | $ | 223,863 | $ | 336,422 | ||||||
Operating income (loss) | 80,317 | 7,044 | (3,337 | ) | 62,475 | |||||||||
Net income (loss) | 42,896 | (20,610 | ) | (16,136 | ) | 37,815 | ||||||||
Basic earnings (loss) per common share* | 1.32 | (0.63 | ) | (0.49 | ) | 1.14 | ||||||||
Diluted earnings (loss) per common share* | 1.30 | (0.63 | ) | (0.49 | ) | 1.13 | ||||||||
2001 | ||||||||||||||
Operating revenues | $ | 487,498 | $ | 278,960 | $ | 246,094 | $ | 384,136 | ||||||
Operating income (loss) | 74,106 | 1,111 | (4,597 | ) | 63,363 | |||||||||
Net income (loss) | 33,809 | (11,140 | ) | (16,488 | ) | 30,975 | ||||||||
Basic earnings (loss) per common share* | 1.06 | (0.35 | ) | (0.51 | ) | 0.96 | ||||||||
Diluted earnings (loss) per common share* | 1.05 | (0.35 | ) | (0.51 | ) | 0.95 |
* The sum of quarterly earnings (loss) per average common share may not equal the annual earnings (loss) per share due to the ongoing change in the weighted average number of common shares outstanding.
southwest gas 2003 annual report
PAGE 61
notes to consolidated financial statements
The demand for natural gas is seasonal, and it is the opinion of management that comparisons of earnings for the interim periods do not reliably reflect overall trends and changes in the operations of the Company. Also, the timing of general rate relief can have a significant impact on earnings for interim periods. See Management’s Discussion and Analysis for additional discussion of operating results.
NOTE 13
merger-related litigation settlements
Litigation related to the now terminated acquisition of the Company by ONEOK, Inc. (“ONEOK”) and the rejection of competing offers from Southern Union Company (“Southern Union”) was resolved during 2002. In August 2002, the Company reached final settlements with both Southern Union and ONEOK related to this litigation. The Company paid Southern Union $17.5 million to resolve all remaining Southern Union claims against the Company and its officers. ONEOK paid the Company $3 million to resolve all claims between the Company and ONEOK. The net after-tax impact of the settlements was a $9 million charge and was reflected in the second quarter 2002 financial statements. The Company and one of its insurance providers were in dispute over whether the insurance coverage applied to the Southern Union settlement and related litigation defense costs. Because of the dispute, the Company did not recognize any benefit for potential insurance recoveries related to the Southern Union settlement in the second quarter of 2002.
In December 2002, the Company negotiated a $16.25 million settlement with the insurance provider related to the coverage dispute. Income from the settlement was recognized in the fourth quarter of 2002 and amounted to $9 million after-tax.
NOTE 14
acquisition of black mountain gas company
In October 2003, the Company acquired all of the outstanding stock of Black Mountain Gas Company.
The assets acquired and the liabilities assumed at the acquisition date were as follows:
(thousands of dollars) | ||||
Gas plant | $ | 23,974 | ||
Less: accumulated depreciation | (5,992 | ) | ||
Net utility plant | 17,982 | |||
Other property and investments | 1,500 | |||
Accounts receivable, net of allowances | 504 | |||
Prepaids and other current assets | 163 | |||
Deferred charges and other assets (includes goodwill of $5,445) | 5,610 | |||
Total assets acquired | 25,759 | |||
Accounts payable | 219 | |||
Customer deposits | 55 | |||
Deferred purchased gas costs | 112 | |||
Accrued general taxes | 144 | |||
Other deferred credits | 1,229 | |||
Total liabilities assumed | 1,759 | |||
Cash acquisition price | $ | 24,000 | ||
southwest gas 2003 annual report
PAGE 62
report of independent auditors
To the Shareholders of
Southwest Gas Corporation:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Southwest Gas Corporation and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for the years ended December 31, 2003 and 2002 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The financial statements of the Company as of December 31, 2001 were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those statements in their report dated February 8, 2002.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement obligations as of January 1, 2003, financial instruments with characteristics of both debt and equity and certain variable interest entities as of July 1, 2003.
PricewaterhouseCoopers LLP
Los Angeles, California
March 11, 2004
southwest gas 2003 annual report
PAGE 63
report of independent public accountants
To the Shareholders of
Southwest Gas Corporation:
We have audited the accompanying consolidated balance sheets of Southwest Gas Corporation (a California corporation) and its subsidiaries (the Company) as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Southwest Gas Corporation and its subsidiaries as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
Las Vegas, Nevada
February 8, 2002
The aforementioned report on the consolidated balance sheets of Southwest Gas Corporation and its subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2001 is a copy of a previously issued Arthur Andersen LLP report. Arthur Andersen LLP has not reissued this report.